10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2006

OR

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

For the transition period from ______________________ to _________________________

Commission file number 001-10608                                 

Florida Public Utilities Company

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

Florida	59-0539080
(State or other jurisdiction of Incorporation or organization)	(I.R.S. Employer Identification Number)

401 South Dixie Highway, West Palm Beach, FL  33401

(Address of principal executive offices, Zip Code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock par value $1.50 per share	American Stock Exchange

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

__________________________________________________________________________________

 (Title of class)

__________________________________________________________________________________

(Title of class)

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

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

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

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

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

Large accelerated filer [  ]

Accelerated filer [  ]

Non-accelerated filer [X]

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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

PART I

Item 1.   Business

General

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

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

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

Business Environment

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

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

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

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

Business Segments

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

Natural Gas

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

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

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

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

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

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

Electric

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

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

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

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

Propane Gas

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

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

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

Strategy

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

Competition

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

Rates and Regulation

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

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

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

Franchises

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

Employees

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

Available Information

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

Item 1A.   Risk Factors

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

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

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

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

Our segments are sensitive to variations in weather.

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

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

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

Natural Gas

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

Electric

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

Propane Gas

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

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

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

General economic conditions may adversely affect our segments.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Problems with operations could materially adversely impact us.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Item 1B.   Unresolved Staff Comments

None

Item 2.   Properties

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

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

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

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

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

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

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

Item 3.   Legal Proceedings

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

West Palm Beach Site

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

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

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

Sanford Site

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

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

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

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

Pensacola Site

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

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

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

Key West Site

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

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

None

Executive Officers of the Registrant

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

Name	Age	Position	Date
John T. English	63	Chairman of the Board	2006 - Present
		Chief Executive Officer	1998 - Present
		President	1997 - Present
		Chief Operating Officer	1997 - 2000
Charles L. Stein	57	Chief Operating Officer	2001 - Present
		Senior Vice President	1997 - Present
George M. Bachman	47	Corporate Secretary	2004 - Present
		Chief Financial Officer	2001 - Present
		Treasurer	2001 - Present

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

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

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

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

PART II

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

Quarterly Stock Prices and Dividends Paid

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

	2006			2005
	Stock Prices		Dividends	Stock Prices *		Dividends
Quarter ended	Low	High	Declared	Low	High	Declared*
March 31	$13.25	$14.50	$0.1033	$11.47	$13.49	$0.1000
June 30	11.86	14.40	0.1075	11.45	12.67	0.1033
September 30	12.61	14.42	0.1075	12.67	16.84	0.1033
December 31	13.10	14.05	0.1075	13.46	16.44	0.1033

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

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

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

Securities Authorized for Issuance under Equity Compensation Plans

Equity Compensation Plan Information
Plan Category	Number of Securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders	72,749*
Equity compensation plans not approved by security holders	-
Total	72,749
* This includes 20,714 shares for the Non-Employee Director Compensation Plan. This plan was adopted by the Board of Directors on March 18, 2005 and was approved at the 2005 meeting of shareholders. This also includes 52,035 shares for the Employee Stock Purchase Plan.

PERFORMANCE GRAPH

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

	12/01	12/02	12/03	12/04	12/05	12/06
Florida Public Utilities Company	100.00	119.25	131.72	165.01	181.67	182.09
Russell 2000	100.00	79.52	117.09	138.55	144.86	171.47
S & P Utilities	100.00	70.01	88.39	109.85	128.35	155.29

Item 6.   Selected Financial Data

(Dollars in thousands, except per share data)
Years Ended December 31,		2006		2005		2004		2003		2002
Revenues	$	134,393	$	130,023	$	110,039	$	102,723	$	88,461
Gross profit	$	48,422	$	47,219	$	40,689	$	37,733	$	34,929
Earnings:
Continuing operations	$	4,169	$	4,248	$	3,594	$	2,522	$	2,761
Discontinued operations (1)		-		-		-		9,901		602
Net income	$	4,169	$	4,248	$	3,594	$	12,423	$	3,363
Earnings per common share (basic and diluted):
Continuing operations	$	0.69	$	0.71	$	0.60	$	0.43	$	0.47
Discontinued operations (1)		-		-		-		1.69		0.10
Total	$	0.69	$	0.71	$	0.60	$	2.12	$	0.57
Dividends declared per common share	$	0.43	$	0.41	$	0.40	$	0.39	$	0.38
Total assets	$	180,913	$	182,666	$	170,503	$	160,944	$	148,487
Utility plant – net	$	129,211	$	123,061	$	117,191	$	107,942	$	103,357
Current debt	$	3,466	$	9,558	$	5,825	$	2,278	$	19,183
Long-term debt	$	50,702	$	50,620	$	50,538	$	50,454	$	50,367
Common shareholders' equity	$	47,572	$	45,503	$	43,213	$	41,463	$	30,883

Note to the Selected Financial Data:

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

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

RESULTS OF OPERATIONS

General

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

Revenues and Gross Profit Summary

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

Revenues and Gross Profit
(Dollars in thousands)
	Year Ended December 31,
	2006	2005	2004
Natural Gas
Revenues	$71,139	$69,094	$55,962
Cost of fuel and other pass through costs	43,909	42,815	34,232
Gross Profit	$27,230	$26,279	$21,730
Units sold: (MDth)	6,230	6,224	6,124
Electric
Revenues	$48,527	$47,450	$42,910
Cost of fuel and other pass through costs	34,259	33,352	29,732
Gross Profit	$14,268	$14,098	$13,178
Units sold: (MWH)	849,124	814,353	766,349
Propane Gas
Revenues	$14,727	$13,479	$11,167
Cost of fuel and other pass through costs	7,803	6,637	5,386
Gross Profit	$ 6,924	$6,842	$5,781
Units sold:  (MDth)	621	640	614
Consolidated
Revenues	$134,393	$130,023	$110,039
Cost of fuel and other pass through costs	85,971	82,804	69,350
Gross Profit	$ 48,422	$ 47,219	$ 40,689

Natural Gas

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

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

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

Electric

Electric revenues increased $1.1 million in 2006 over 2005.  Cost of fuel and other costs that were passed through to customers contributed approximately $900,000 of the increase.Gross profit increased $170,000 or 1% in2006 over 2005.  The increase in gross profit was primarily due to a slight increase in customer growth and units sold.

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

Propane Gas

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

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

Operating Expenses

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

Operating Expenses (Dollars in thousands)
	Year Ended December 31,
	2006	2005	2004
Natural gas	$   21,112	$   20,230	$   16,752
Electric	11,215	10,596	9,825
Propane gas	5,918	5,756	5,126
Total Operating Expenses	$ 38,245	$   36,582	$   31,703

Natural Gas

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

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

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

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

Electric

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

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

Propane Gas

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

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

Administrative Expenses

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

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

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

Total Other Income and Deductions

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

Merchandise and Services Revenue and Expenses

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

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

Interest Expenses

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

Other

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

Income Taxes

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

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

Liquidity and Capital Resources

Summary of Primary Sources and Uses of Cash (Dollars in thousands)
	Year Ended December 31,
	2006	2005	2004
Sources of Cash:
Operating activities, including working capital changes	$20,090	$10,213	$11,673
Net proceeds on short-term debt	-	3,733	3,547
Other sources of cash	1,179	1,214	648
Uses of Cash:
Construction expenditures	13,116	12,441	13,731
Dividends paid	2,551	2,448	2,368
Net payment on short-term debt	6,092	-	-
Other uses of cash	121	75	129
Net (use) source of cash	$ (611)	$    196	$   (360)

Cash Flows

Operating Activities

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

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

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

Investing Activities

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

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

Financing Activities

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

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

Capital Resources

We currently have a $12 million line of credit, which expires on July 1, 2008. Upon 30 days notice by us we can increase the line of credit to a maximum of $20 million.  The line of credit contains affirmative and negative covenants that, if violated, would give the bank the right to accelerate the due date of the loan to be immediately payable. The covenants include certain financial ratios.  All ratios are currently met and management believes we are in full compliance with all covenants and anticipates continued compliance.  We reserve $1 million of the line of credit to cover expenses for any major storm repairs in our electric segment and an additional $250,000 for a letter of credit insuring propane gas facilities. As of December 31, 2006, the amount borrowed on the line of credit was $3.5 million.The line of credit, long-term debt and preferred stock as of December 31, 200 6 comprised 54% of total capitalization and debt.

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

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

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

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

Capital Requirements

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

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

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

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

Outlook

Pension and Insurance Expenses

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

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

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

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

Electric Power Supply Contracts

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

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

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

Propane Gas

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

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

Over-earnings-Natural Gas Segment

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

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

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

Electric Customers

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

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

Natural Gas Customers

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

Indiantown Gas Agreement

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

Storm Preparedness Expenses

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

Land Purchase

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

Contractual Obligations

Table of Contractual Obligations (Dollars in thousands)
Payments due by period:	Total	Less than     1 year	1 to 3 years	3 to 5 years	More than    5 years
Long-term Debt Obligations	$52,500	$          -	$2,818	$2,818	$46,864
Long-term Debt Interest	63,904	3,949	7,623	7,074	45,258
Operating Lease Obligations	362	161	163	38	-
Natural Gas and Propane Gas Purchase Obligations	64,904	37,768	16,244	4,568	6,324
Electric Purchase Obligations	268	53	106	61	48
Other Purchase Obligations	2,698	922	1,698	21	57
Total	$184,636	$42,853	$28,652	$14,580	$98,551

Long-term Debt Obligations

The Long-term debt obligations are principal amounts.

Long-term Debt Interest

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

Operating Lease Obligations

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

Purchase Obligations

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

Pension, Medical Postretirement and Other Obligations

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

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

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

Dividends

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

Other

Impact of Recent Accounting Standards

Financial Accounting Standard Board Interpretation No. 48

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

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

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

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

Financial Accounting Standard No. 157

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

Financial Accounting Standard No. 158

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

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

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

FASB 158 Implementation Summary (Dollars in thousands)
	December 31, 2006
	Before Application of SFAS 158	Adjustment	After Application of SFAS 158
Assets:
Other regulatory assets- retirement plans	$           -	$587	$587
Liabilities and Equity:
Accumulated other comprehensive income/(loss)	-	(103)	(103)
Other accruals and payables	2,034	151	2,185
Long term medical and pension reserve	4,129	602	4,731
Deferred income taxes	16,167	(63)	16,104

Staff Accounting Bulletin No. 108

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

Critical Accounting Policies and Estimates

Regulatory Accounting

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

Use of Estimates

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

Revenue Recognition

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

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

Effects of Inflation

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

Environmental Matters

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Forward-Looking Statements (Cautionary Statement)

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

·

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

·

Other insurance costs will increase in 2007.

·

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

·

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

·

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

·

Propane gas hedging activity may occur in 2007.

·

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

·

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

·

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

·

The development in Indiantown will occur as estimated.

·

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

·

Pension expenses are expected to increase in 2007.

·

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

·

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

·

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

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

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

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

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

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

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

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

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

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

Item 8.     Financial Statements and Supplementary Data

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

		Years Ended December 31
Revenues		2006		2005		2004
Natural gas	$	71,139	$	69,094	$	55,962
Electric		48,527		47,450		42,910
Propane gas		14,727		13,479		11,167
Total revenues		134,393		130,023		110,039
Cost of Fuel and Other Pass Through Costs		85,971		82,804		69,350
Gross Profit		48,422		47,219		40,689
Operating Expenses
Operation		24,034		22,881		20,068
Maintenance		3,484		3,566		2,982
Depreciation and amortization		7,742		7,266		5,900
Taxes other than income taxes		2,985		2,869		2,753
Total operating expenses		38,245		36,582		31,703
Operating Income		10,177		10,637		8,986
Other Income and (Deductions)
Merchandise and service revenue		4,322		4,590		3,366
Merchandise and service expenses		(4,071)		(4,664)		(3,326)
Other income		620		569		625
Other deductions		(33)		(29)		20
Interest expense on long-term debt		(3,949)		(3,949)		(3,949)
Interest expense on short-term borrowings		(108)		(79)		(42)
Customer deposits and other interest expense		(551)		(540)		(471)
Total other deductions – net		(3,770)		(4,102)		(3,777)
Earnings Before Income Taxes		6,407		6,535		5,209
Income Taxes		(2,238)		(2,287)		(1,615)
Net Income		4,169		4,248		3,594
Preferred Stock Dividends		29		29		29
Earnings for Common Stock	$	4,140	$	4,219	$	3,565
Earnings Per Common Share (basic and diluted)	$	.69	$	.71	$	.60
Dividends Declared Per Common Share	$	.43	$	.41	$	.40
Average Shares Outstanding		5,993,589		5,952,684		5,908,220

See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

		Years Ended December 31
		2006		2005		2004
Net income	$	4,169	$	4,248	$	3,594
Other comprehensive income/(loss), net:
Retirement plans adjustment		(166)		-		-
Deferred income taxes benefit		63		-		-
Comprehensive income	$	4,066	$	4,248	$	3,594

See Notes to Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS (Dollars in thousands)
		December 31,
ASSETS		2006		2005
Utility Plant
Natural gas	$	95,393	$	89,835
Electric		72,776		70,084
Propane gas		17,153		15,500
Common		3,646		3,859
Total		188,968		179,278
Less accumulated depreciation		59,757		56,217
Net utility plant		129,211		123,061
Current Assets
Cash		84		695
Accounts receivable		12,199		15,780
Notes receivable		298		299
Allowance for uncollectible accounts		(429)		(272)
Unbilled receivables		1,957		1,918
Inventories (at average or unit cost)		4,120		3,781
Prepaid expenses		962		951
Income tax prepayments		98		1,159
Under-recovery of fuel costs		862		3,375
Total current assets		20,151		27,686
Other Assets
Investments held for environmental costs		3,364		3,258
Other regulatory assets – storm reserve		270		452
Other regulatory assets – environmental		8,284		8,868
Other regulatory assets – retirement plans		587		-
Long-term receivables and other investments		5,740		5,794
Deferred charges		6,496		6,751
Goodwill		2,405		2,405
Intangible assets (net)		4,405		4,391
Total other assets		31,551		31,919
Total	$	180,913	$	182,666

See Notes to Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS (Dollars in thousands)
		December 31,
CAPITALIZATION AND LIABILITIES		2006		2005
Capitalization
Common shareholders' equity	$	47,572	$	45,503
Preferred stock		600		600
Long-term debt		50,702		50,620
Total capitalization		98,874		96,723
Current Liabilities
Line of credit		3,466		9,558
Accounts payable		10,279		13,166
Insurance accrued		181		296
Interest accrued		789		1,014
Other accruals and payables		2,185		1,984
Taxes accrued		1,277		1,512
Deferred income tax		579		1,066
Over-earnings liability		722		700
Over-recovery of fuel costs		3,656		-
Over-recovery of conservation		355		24
Customer deposits		9,608		8,851
Total current liabilities		33,097		38,171
Other Liabilities
Deferred income taxes		16,104		17,568
Unamortized investment tax credits		335		411
Environmental liability		13,753		14,001
Regulatory liability – cost of removal		8,800		8,256
Regulatory tax liabilities		876		991
Long-term medical and pension reserve		4,731		2,663
Customer advances for construction		2,707		2,346
Regulatory liability – storm reserve		1,636		1,536
Total other liabilities		48,942		47,772
Total	$	180,913	$	182,666
See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in thousands)
		December 31,
		2006		2005
Common Shareholders' Equity
Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,166,648 shares in 2006; issued 6,152,676 shares in 2005	$	9,250	$	9,229
Paid-in capital		6,054		5,998
Retained earnings		35,213		33,625
Accumulated other comprehensive income/(loss), retirement plan adjustment, net of income tax benefit		(103)		-
Treasury stock - at cost (160,349 shares in 2006, 188,994 shares in 2005)		(2,842)		(3,349)
Total common shareholders' equity		47,572		45,503
Preferred Stock
4 ¾% Series A, $100 par value, redemption price $106, authorized and outstanding 6,000 shares		600		600
4 ¾% Series B Cumulative Preferred, $100 par value, redemption price $101, authorized 5,000 and none issued		-		-
$1.12 Convertible Preference, $20 par value, redemption price $22, authorized 32,500 and none issued		-		-
Total preferred stock		600		600
Long-Term Debt
First mortgage bonds series
9.57 % due 2018		10,000		10,000
10.03 % due 2018		5,500		5,500
9.08 % due 2022		8,000		8,000
4.90 % due 2031		14,000		14,000
6.85 % due 2031		15,000		15,000
Unamortized debt discount		(1,798)		(1,880)
Total long-term debt		50,702		50,620
Total Capitalization	$	98,874	$	96,723
See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in thousands)
	Common Stock
	Shares Issued	Aggregate Par Value	Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive (Loss)	Treasury Shares Cost	Treasury Shares	Common Shareholders’ Equity
Balances as of December 31, 2003	6,097,478	$9,146	$5,632	$30,638	$     -	$(3,953)	223,062	$41,463
Net income	-	-	-	3,594	-	-	-	3,594
Dividends	-	-	-	(2,383)	-	-	-	(2,383)
Stock plans	32,619	49	174	-	-	316	(17,821)	539
Balances as of December 31, 2004	6,130,097	9,195	5,806	31,849	-	(3,637)	205,241	43,213
Net income	-	-	-	4,248	-	-	-	4,248
Dividends	-	-	-	(2,472)	-	-	-	(2,472)
Stock plans	22,579	34	192	-	-	288	(16,247)	514
Balances as of December 31, 2005	6,152,676	9,229	5,998	33,625		(3,349)	188,994	45,503
Net income	-	-	-	4,169	-	-	-	4,169
Other comprehensive loss, retirement plans adjustment, net of tax	-	-	-	-	(103)	-	-	(103)
Dividends	-	-	-	(2,581)	-	-	-	(2,581)
Stock plans	13,972	21	56	-	-	507	(28,645)	584
Balances as of December 31, 2006	6,166,648	$9,250	$6,054	$35,213	$      (103)	$(2,842)	160,349	$47,572

See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in thousands)
		Years Ended December 31,
		2006		2005		2004
Cash Flows from Operating Activities:
Net income	$	4,169	$	4,248	$	3,594
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		7,742		7,266		5,900
Deferred income taxes		(2,003)		(153)		2,470
Bad debt expense		623		359		409
Investment tax credits		(75)		(81)		(83)
Other		805		751		121
Interest income from sale of non-utility property		(252)		(192)		(271)
Compensation expense from the issuance of stock		88		58		91
Effects of changes in:
Receivables		3,115		(4,513)		(1,688)
Unbilled receivables		(39)		367		(612)
Inventories and prepayments		711		(495)		2,746
Accounts payable and accruals		(976)		5,560		1,131
Over (under) recovery of fuel and other pass through costs		6,500		(3,171)		(1,991)
Area expansion program deferred costs		238		109		(372)
Environmental liability		584		429		(586)
Other		(1,140)		(329)		814
Net cash provided by operating activities		20,090		10,213		11,673
Cash Flows from Investing Activities:
Construction expenditures		(13,116)		(12,441)		(13,731)
Customer advances received for construction		361		454		144
Purchase of long-term investments		(106)		(75)		(34)
Proceeds received on notes receivable		321		304		57
Issuance of notes receivable		-		-		(95)
Other		(15)		-		-
Net cash used in investing activities		(12,555)		(11,758)		(13,659)
Cash Flows from Financing Activities:
Net change in short-term borrowings		(6,092)		3,733		3,547
Proceeds from common stock plans		497		456		447
Dividends paid		(2,551)		(2,448)		(2,368)
Net cash provided by (used in) financing activities		(8,146)		1,741		1,626
Net Increase (Decrease) in Cash		(611)		196		(360)
Cash at Beginning of Year		695		499		859
Cash at End of Year	$	84	$	695	$	499
Supplemental Cash Flow Information
Cash was paid during the years as follows:
Interest	$	4,777	$	4,469	$	4,357
Income taxes	$	3,298	$	2,698	$	1,215

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.

Summary of Significant Accounting and Reporting Policies

A. General

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

B. Basis of Presentation

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

C. Use of Estimates

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

D. Reclassifications

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

E. Regulation

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

Summary of Regulatory Assets and Liabilities
(Dollars in thousands)
	2006	2005
Assets
Deferred development costs  (1)	$  3,952	$  4,190
Unamortized fuel related regulatory costs (6)	48	24
Environmental assets (2)	8,284	8,868
Storm Reserve assets (3)	270	452
Deferred retirement plan costs (5)	587	-
Unamortized Rate Case expense	368	541
Under-recovery of fuel costs	862	3,375
Unamortized piping and conversion costs   (1)	1,521	1,587
Unamortized loss on reacquired debt   (1)	209	227
Total Regulatory Assets	$16,101	$19,264
Liabilities
Tax liabilities	$     876	$     991
Cost of removal	8,800	8,256
Storm reserve liabilities	1,636	1,536
Over-recovery of fuel costs	3,656	-
Over-recovery of conservation	355	24
Over-earnings liability (4)	722	700
Total Regulatory Liabilities	$16,045	$11,507

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

(6)

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

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

F. Derivatives

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

G. Revenue Recognition

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

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

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

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

H. Allowance for Doubtful Accounts

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

Allowance for Doubtful Accounts (Dollars in thousands)
	Balance at Beginning of Year	Write-offs	Provisions to Bad Debt Expense	Balance at End of Year
2004	$ 180	320	409	$ 269
2005	$ 269	356	359	$ 272
2006	$ 272	466	623	$ 429

I. Utility Plant and Depreciation

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

Utility Plant
(Dollars in thousands)
Plant Classification	Annual Composite Depreciation Rate	2006	2005
Land		$      1,130	$      1,124
Buildings	2.0% to 4.9%	6,991	6,862
Distribution	2.0% to 8.6%	158,010	147,580
Transmission	2.2% to 3.8%	6,878	6,799
Equipment	2.0% to 20.0%	12,700	11,534
Furniture and Fixtures	4.8% to 20.0%	392	369
Work-in-Progress		2,867	5,010
		$ 188,968	$ 179,278

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

J. Impact of Recent Accounting Standards

Financial Accounting Standard Board Interpretation No. 48

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

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

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

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

Financial Accounting Standard No. 157

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

Financial Accounting Standard No. 158

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

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

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

FASB 158 Implementation Summary (Dollars in thousands)
	December 31, 2006
	Before Application of SFAS 158	Adjustment	After Application of SFAS 158
Assets:
Other regulatory assets- retirement plans	$          -	$587	$587
Liabilities and Equity:
Accumulated other comprehensive income/(loss)	-	(103)	(103)
Other accruals and payables	2,034	151	2,185
Long term medical and pension reserve	4,129	602	4,731
Deferred income taxes	16,167	(63)	16,104

Staff Accounting Bulletin No. 108

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

2.  Goodwill and Intangible Assets

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

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

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

Intangible Assets
(Dollars in thousands)
		2006	2005
Customer distribution rights	(Indefinite life)	$ 1,900	$ 1,900
Customer relationships	(Indefinite life)	900	900
Software	(Five to nine year life)	3,122	2,971
Non-compete agreement	(Five year life)	-	35
Accumulated amortization		(1,517)	(1,415)
Total intangible assets, net of amortization		$4,405	$ 4,391

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

3. Over-earnings-Natural Gas

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

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

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

4. Storm Reserves

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

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

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

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

5. Income Taxes

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

A. Income Taxes related to Deferred Gain on Water Sale

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

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

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

B. Provision for Income Taxes

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

(Dollars in thousands)		Years ended December 31,
		2006		2005		2004
Current payable
Federal	$	3,652	$	2,150	$	(566)
State		664		370		(96)
Current – net		4,316		2,520		(662)
Deferred
Federal		(1,723)		(143)		2,003
State		(280)		(9)		358
Deferred – net		(2,003)		(152)		2,361
Investment tax credit		(75)		(81)		(84)
Total income taxes	$	2,238	$	2,287	$	1,615

C. Effective Tax Rate Reconciliation

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

(Dollars in thousands)		Years ended December 31,
		2006		2005		2004
Federal income tax at statutory rate (34%)	$	2,178	$	2,222	$	1,771
State income tax, net of federal benefit (5.5%)		233		237		189
Investment tax credit		(75)		(81)		(84)
Tax exempt interest		(85)		(71)		(94)
Other		(13)		(20)		(167)
Total provision for income taxes	$	2,238	$	2,287	$	1,615

D. Deferred Income Taxes

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

(Dollars in thousands)	Years ended December 31,
Deferred tax assets:	2006	2005
Environmental	$    2,063	$        1,932
Self insurance	774	731
Storm reserve liability	509	408
Vacation pay	357	320
Other deferred credits	15	61
Allowance for uncollectible accounts receivable	162	103
General liability	68	111
Rate refund	271	263
Pension	789	286
Under/over-recovery of conservation costs	134	9
Other	37	37
Total deferred tax assets	5,179	4,261
Deferred tax liabilities:
Utility plant related	20,274	20,319
Deductible intangibles	696	577
Under-recovery of fuel costs	643	1,704
Rate case expense	138	204
Loss on reacquired debt	79	85
Other	32	6
Total deferred tax liabilities	21,862	22,895
Net deferred income taxes liabilities	$   16,683	$   18,634

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

(Dollars in thousands)	2006	2005
Deferred income tax – current	$        579	$         1,066
Deferred income tax – long term	16,104	17,568
Net deferred income tax liabilities	$   16,683	$       18,634

E. IRS Audit

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

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

6.   Capitalization

A. Stock Dividend

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

B. Common Shares Reserved

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

Dividend Reinvestment Plan	54,071
Employee Stock Purchase Plan	52,035
Board Compensation Plan	20,714

C. Preferred Stock

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

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

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

D. Dividend Restriction

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

E. Treasury Shares

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

F. Employee Stock Purchase Plan

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

G. Dividend Reinvestment Plan

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

7.  Long-term Debt

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

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

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

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

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

Annual Maturities of Long-Term Debt (Dollars in thousands)
	Total	2007	2008	2009	2010	2011	Thereafter
Long-term Debt	$52,500	-	$1,409	$1,409	$1,409	$1,409	$ 46,864

8.  Notes Payable

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

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

Year	Rate
2006	6.2%
2005	5.3%
2004	3.3%

9. Fair Value of Financial Instruments

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

	2006		2005
(Dollars in thousands)	Carrying Amounts	Approximate Fair Value	Carrying Amounts	Approximate Fair Value
Long-term debt	$ 52,500	$63,000	$52,500	$ 63,000

10. Contingencies

Environmental

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

(Dollars in thousands)

Site	Range From	Range To
West Palm Beach	$      4,801	$   18,027
Sanford	710	710
Pensacola and Other	110	110
Total	$      5,621	$   18,847

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

West Palm Beach Site

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

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

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

Sanford Site

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

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

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

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

Pensacola Site

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

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

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

Key West Site

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

11. Commitments

A. General

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

B. Operating Leases

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

	2007	2008	2009	2010	2011
Operating Lease Obligations	$161,000	$116,000	$47,000	$38,000	$        -

12.   Employee Benefit Plans

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

A.  Pension Plan

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

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

Benefit Obligations and Funded Status
			Years Ended December 31,
			2006	2005	2004
(1)	Change in Projected Benefit Obligation
	(a)	Projected Benefit Obligation at the Beginning of the Year	$36,349,925	$34,926,383	$31,540,942
	(b)	Service Cost	1,225,495	1,195,723	1,084,564
	(c)	Interest Cost	2,160,719	2,000,099	1,940,122
	(d)	Actuarial (Gain) or Loss	541,865	(842,777)	1,708,132
	(e)	Benefits Paid	(1,529,258)	(1,514,341)	(1,347,377)
	(f)	Change in Plan Provisions	-	584,838	-
	(g)	Curtailment	(97,858)	-	-
	(h)	Projected Benefit Obligation at the End of the Year	$38,650,888	$36,349,925	$34,926,383
	(i)	Accumulated Benefit Obligation at the End of the Year	$33,693,860	$31,966,513	$30,518,393
(2)	Change in Plan Assets
	(a)	Fair Value of Plan Assets at the Beginning of the Year	$32,936,666	$32,385,214	$31,081,063
	(b)	Actual Return on Plan Assets	3,977,806	2,065,793	2,651,528
	(c)	Benefits Paid	(1,529,258)	(1,514,341)	(1,347,377)
	(d)	Employer Contributions	250,000	-	-
	(e)	Fair Value of Assets at the End of the Year	$35,635,214	$32,936,666	$32,385,214
(3)	Funded Status: (2)(e) - (1)h)		$(3,015,674)	$(3,413,259)	$(2,541,169)
(4)	Amounts Recognized in the Statement of Financial Position Before Applying FAS 158
	(a)	Prepaid (Accrued) Benefit Cost	$(2,070,740)	$(721,333)	$725,619
	(b)	Net Asset (liability)	$(2,070,740)	$(721,333)	$725,619
	(c)	Charge to Accumulated Other Comprehensive Income:	-	-	-
(5)	Adjustments Caused by Applying FAS 158
	(a)	Increase in Net Asset (Liability): (3) – (4)(b)	$(944,934)	N/A	N/A
	(b)	Increase in Charge to Accumulated Other Comprehensive Income:	207,885	N/A	N/A
	(c)	Increase in Charge to Regulatory Asset –retirement plans	737,049	N/A	N/A
	(d)	Subtotal of Adjustments: (a)+(b)+(c)	$             -	N/A	N/A
(6)	Amount Recognized in Statement of Financial Position After applying FAS 158
	(a)	Net Asset (Liability): (4)(b) + (5)(a)	$(3,015,674)	$(721,333)	$725,619
	(b)	Charge to Accumulated Other Comprehensive Income: (4)(c) + (5)(b)	$207,885	-	-
	(c)	Regulatory Asset-Retirement Plans (5) (c)	$737,049	-	-
(7)	Net Asset (Liability) Recognized in the Statement of Financial Position After applying FAS 158

	(a)	Noncurrent Assets	-	N/A	N/A
	(b)	(Current Liabilities)	-	N/A	N/A
	(c)	(Noncurrent Liabilities)	$(3,015,674)	N/A	N/A
	(d)	Total Net Asset (Liability): (a) + (b) + (c)	$(3,015,674)	N/A	N/A
(8)	Amount Recognized in Accumulated Other Comprehensive Income And Regulatory Asset –Retirement Plans After applying FAS 158
	(a)	Transition Obligation (Asset)	-	N/A	N/A
	(b)	Prior Service Cost (Credit)	$3,992,489	N/A	N/A
	(c)	Net (Gain) or Loss	(3,047,555)	N/A	N/A
	(d)	Total	$944,934	N/A	N/A
(9)	Weighted Average Assumption at End of Year
	(a)	Discount Rate	6.00%	5.90%	5.75%
	(b)	Rate of Compensation Increase	3.25%	3.15%	3.00%
	(c)	Mortality	GAM 83	GAM 83	GAM 83

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

Net Periodic Pension Costs
			Years Ended December 31,
			2006	2005	2004
(1)	Service Cost		$1,225,495	$1,195,723	$1,084,564
(2)	Interest Cost		2,160,719	2,000,099	1,940,122
(3)	Expected Return on Plan Assets		(2,426,064)	(2,485,985)	(2,591,099)
(4)	Amortization of Transition Obligation/(Asset)		-	-	-
(5)	Amortization of Prior Service Cost		737,115	737,115	698,211
(6)	Amortization of Net (Gain) or Loss		-	-	-
(7)	Total FAS 87 Net Periodic Pension Cost		$1,697,265	$1,446,952	$1,131,798
(8)	FAS 88 Charges / (Credits)
	(a)	Curtailment	(97,858)	-	-
(9)	Total Net Periodic Pension Cost and Comprehensive Income		$1,599,407	$1,446,952	$1,131,798
(10)	Weighted Average Assumptions
	(a)	Discount Rate at Beginning of the Period	5.90%	5.75%	6.25%
	(b)	Expected Return on Plan Assets	8.50%	8.50%	8.50%
	(c)	Rate of Compensation Increase	3.15%	3.00%	3.50%

Plan Assets
			Target	Percentage of Plan
			Allocation	Assets at December 31
			2007	2006	2005	2004
(1)	Plan Assets
	(a)	Equity Securities	40%-60%	68%	67%	69%
	(b)	Debt Securities	25%-40%	30%	32%	30%
	(c)	Real Estate	5%-15%	0%	0%	0%
	(d)	Other	5%-15%	2%	1%	1%
	(e)	Total		100%	100%	100%

Expected Return on Plan Assets

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

Investment Policy and Strategy

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

Cash Flows
(1)	Expected Contributions for Fiscal Year Ending December 31, 2007
	(a)	Expected Employer Contributions	$250,000
	(b)	Expected Employee Contributions	-
(2)	Estimated Future Benefit Payments Reflecting Expected Future Service for the years ending December 31,
	(a)	2007	$1,756,069
	(b)	2008	$1,839,843
	(c)	2009	$1,975,656
	(d)	2010	$2,092,003
	(e)	2011	$2,182,628
	(f)	2012 – 2016	$13,040,794
(3)	Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/07		-

Other Accounting Items
			Years Ended December 31,
			2006	2005	2004
(1)	Market-Related Value of Assets as of the Beginning of fiscal year		$29,290,131	$30,016,761	$31,222,154
(2)	Amount of Future Annual Benefits of Plan Participants Covered by Insurance Contracts Issued by the Employer or Related Parties		$ 0	$ 0	$ 0
(3)	Alternative Amortization Methods Used to Amortize
	(a)	Prior Service Cost	Straight Line	Straight Line	Straight Line
	(b)	Unrecognized Net (Gain) or Loss	Straight Line	Straight Line	Straight Line
(4)	Average Future Service		10.80	10.95	10.95
(5)	Employer Commitments to Make Future Plan Amendments (that Serve as the Basis for the Employer’s Accounting for the Plan)		None	None	None
(6)	Description of Special or Contractual Termination Benefits Recognized During the Period		N/A	N/A	N/A
(7)	Cost of Benefits Described in (6)		N/A	N/A	N/A
(8)	Explanation of Any Significant Change in Benefit Obligation or Plan Assets not Otherwise Apparent in the Above Disclosures		N/A	N/A	N/A
(9)	Measurement Date Used		December 31, 2006	December 31, 2005	December 31, 2004

B.  Medical Plan

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

Benefit Obligations and Funded Status
					Fiscal Year Ending
					12/31/2006	12/31/2005		12/31/2004
(1)	Change in Accumulated Postretirement Benefit Obligation
	(a)		Accumulated Postretirement Benefit Obligation at the Beginning of the Year		$2,343,583	$1,925,254		$1,807,999
	(b)		Service Cost		59,982	100,054		70,300
	(c)		Interest Cost		105,483	127,312		106,079
	(d)		Actuarial (Gain) or Loss		(568,755)	282,812		32,646
	(e)		Benefits Paid		(117,459)	(135,166)		(119,005)
	(f)		Change in Plan Provisions		-	-		-
	(g)		Plan Participant's Contributions		42,519	43,317		27,235
	(h)		Accumulated Postretirement Benefit Obligation at the End of the Year		$1,865,353	$2,343,583		$1,925,254
(2)	Change in Plan Assets
	(a)		Fair Value of Plan Assets at the Beginning of the Year		$ -	$ -		$ -
		(b)		Benefits Paid	(117,459)		(135,166)		(119,005)
		(c)		Employer Contributions	74,940		91,849		91,770
		(d)		Plan Participant's Contributions	42,519		43,317		27,235
		(e)		Fair Value of Assets at the End of the Year	$ -		$ -		$ -
(3)		Net Amount Recognized
		(a)		Funded Status: (2)(e) - (1)(h)	$(1,865,353)		$(2,343,583)		$(1,925,254)
(4)		Amounts Recognized in the Statement of Financial Position Before Applying FAS 158
		(a)		Prepaid (Accrued) Benefit Cost	(2,057,833)		(1,942,393)		(1,763,980)
		(b)		(Additional Liability due to an Unfunded ABO)	-		-		-
		(c)		Intangible Asset	-		-		-
		(d)		Net Asset (Liability):  (a) + (b) + (c)	$(2,057,833)		$(1,942,393)		$(1,763,980)
		(e)		Charged to Accumulated Other Comprehensive Income:	-		-		-
(5)		Adjustments Caused by Applying FAS 158
		(a)		Increase in Net Asset (Liability): (3) – (4)(d)	$192,480		N/A		N/A
		(b)		Increase in charge to Accumulated Other Comprehensive Income:	(42,346)		N/A		N/A
		(c)		Increase in charge to Regulatory Asset-retirement plans	(150,134)		N/A		N/A
		(d)		Subtotal of Adjustments: (a) + (b) + (c)	$ -		N/A		N/A
(6)		Amounts Recognized in the Statement of Financial Position After applying FAS 158
		(a)		Net Asset (Liability): (4)(d) +(5)(a)	(1,865,353)		(1,942,393)		(1,763,980)
		(b)		Charge to Accumulated Other Comprehensive Income: (4)(e) + (5)(b)	(42,346)		-		-
		(c)		Charge to Regulatory Asset-Retirement Plans (5)(c)	(150,134)		-		-
(7)		Net Asset (Liability) Recognized in the Statement of Financial Position After Applying FAS 158
		(a)		Noncurrent Assets	$ -		N/A		N/A
		(b)		(Current Liabilities)	(150,589)		N/A		N/A
		(c)		(Noncurrent Liabilities)	(1,714,764)		N/A		N/A
		(d)		Total Net Asset (Liability): (a) + (b) + (c)	$(1,865,353)		N/A		N/A
(8)		Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Asset After Applying FAS 158
		(a)		Transition Obligation (Asset)	$ -		N/A		N/A
		(b)		Prior Service Cost (Credit)	-		N/A		N/A
		(c)		Net (Gain) or Loss	(192,480)		N/A		N/A
		(d)		Total	$(192,480)		N/A		N/A
(9)		Weighted Average Assumptions at the End of the Year
		(a)		Discount Rate	6.00%		5.90%		5.75%
		(b)		Rate of Compensation Increase	N/A		N/A		N/A
		(c)		Mortality	GAM 83		GAM 83		GAM 83
(10)		Assumed Health Care Cost Trend Rates
		(a)		Health Care Cost Trend Rate Assumed for Next Year	11.50%		9.00%		10.00%
		(b)		Ultimate Rate	5.00%		5.00%		5.00%
		(c)		Year that the Ultimate Rate is Reached	2014		2010		2010

Net Periodic Postretirement Benefit Cost

			Years ended December 31,
			2006		2005		2004
(1)	Service Cost		$59,982		$100,054		$70,300
(2)	Interest Cost		105,483		127,312		106,079
(3)	Amortization of Transition Obligation/(Asset)		42,896		42,896		42,896
(4)	Amortization of Prior Service Cost		-		-		-
(5)	Amortization of Net (Gain) or Loss		(17,981)		-		(8,666)
(6)	Total Net Periodic Benefit Cost		$190,380		$270,262		$210,609
(7)	Weighted Average Assumptions
	(a)	Discount Rate	5.90%		5.75%		6.25%
	(b)	Expected Return on Plan Assets	N/A		N/A		N/A
	(c)	Rate of Compensation Increase	N/A		N/A		N/A
(8)	Assumed Health Care Cost Trend Rates
	(a)	Health Care Cost Trend Rate Assumed for	12.50%		10.00%		12.00%
		Current Year
	(b)	Ultimate Rate	5.00%		5.00%		5.00%
	(c)	Year that the Ultimate Rate is Reached	2014		2010		2010
Expected Amortizations
			Years ended December 31,
			2007		2006		2005
(1)	Expected Amortization of Transition Obligation (Asset)		-		N/A		N/A
(2)	Expected Amortization of Prior Service Cost (Credit)		-	N/A		N/A
(3)	Expected Amortization of Net Loss (Gain)		$(536)	N/A		N/A
(9)	Impact of One-Percentage-Point Change in
	Assumed Health Care Cost Trend Rates		Increase	Decrease
	(a)	Effect on Service Cost + Interest Cost	$20,533	$(17,812)
	(b)	Effect on Postretirement Benefit Obligation	$203,809	$(179,005)

Plan Assets
			Target	Percentage of Plan
			Allocation	Assets at December 31
			2007	2006	2005	2004
(1)	Plan Assets
	(a)	Equity Securities	N/A	N/A	N/A	N/A
	(b)	Debt Securities	N/A	N/A	N/A	N/A
	(c)	Real Estate	N/A	N/A	N/A	N/A
	(d)	Other	N/A	N/A	N/A	N/A
	(e)	Total	N/A	N/A	N/A	N/A

Cash Flows
(1)	Expected Contributions for Fiscal Year Ending 12/31/2007
	(a)	Expected Employer Contributions				$150,589
	(b)	Expected Employee Contributions				$48,832
(2)	Estimated Future Benefit Payments Reflecting Expected Future Service for the Fiscal Year(s) Ending
			Total	Medicare Part-D Reimbursement	Employee	Employer
	(a)	12/31/2007	$199,421	$0	$48,832	$150,589
	(b)	12/31/2008	$143,659	$8,266	$36,130	$99,263
	(c)	12/31/2009	$146,580	$8,749	$36,535	$101,296
	(d)	12/31/2010	$160,560	$9,504	$41,759	$109,297
	(e)	12/31/2011	$199,681	$10,062	$51,049	$138,570
	(f)	12/31/2012 – 12/31/2016	$1,407,957	$61,062	$350,375	$996,520
(3)	Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/07					$0

Other Accounting Items
	Years Ended December 31,
	2006	2005	2004

(1)	Market-Related Value of Assets		N/A	N/A	N/A
(2)	Amount of Future Annual Benefits of Plan Participants Covered by Insurance Contracts Issued by the Employer or Related Parties		-	-	-
(3)	Alternative Amortization Methods Used to Amortize
	(a)	Prior Service Cost	Straight Line	Straight Line	Straight Line
	(b)	Unrecognized Net (Gain) or Loss	Straight Line	Straight Line	Straight Line
(4)	Average Future Service		11.10	13.35	12.48
(5)	Employer Commitments to Make Future Plan Amendments (that Serve as the Basis for the Employer’s Accounting for the Plan)		None	None	None
(6)	Description of Special or Contractual Termination Benefits Recognized During the Period		N/A	N/A	N/A
(7)	Cost of Benefits Described in (6)		N/A	N/A	N/A
(8)	Explanation of Any Significant Change in Benefit Obligation or Plan Assets not Otherwise Apparent in the Above Disclosures		N/A	N/A	N/A
(9)	Measurement Date Used		December 31, 2006	December 31, 2005	December 31, 2004

Discount Rate Assumption

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

Actuarial Equivalent

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

Voluntary Prescription Drug Coverage

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

C. Health Plan

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

D. 401K Plan

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

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

E. Employee Stock Purchase Plan

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

13.   Segment Information

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

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

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

(Dollars in thousands)		2006		2005		2004
Revenues
Natural gas	$	71,139	$	69,094	$	55,962
Electric		48,527		47,450		42,910
Propane gas		14,727		13,479		11,167
Consolidated	$	134,393	$	130,023	$	110,039
Operating income, excluding income tax
Natural gas	$	6,118	$	6,049	$	4,978
Electric		3,053		3,502		3,353
Propane gas		1,006		1,086		655
Consolidated	$	10,177	$	10,637	$	8,986
Identifiable assets
Natural gas	$	93,689	$	96,106	$	87,729
Electric		52,251		51,317		48,687
Propane gas		19,239		19,567		15,731
Common		15,734		15,676		18,356
Consolidated	$	180,913	$	182,666	$	170,503
Depreciation and amortization
Natural gas	$	4,095	$	3,928	$	2,752
Electric		2,610		2,404		2,323
Propane gas		720		621		560
Common		317		313		265
Consolidated	$	7,742	$	7,266	$	5,900
Construction expenditures
Natural gas	$	7,643	$	6,357	$	5,314
Electric		3,184		3,775		6,793
Propane gas		1,885		2,133		1,339
Common		404		176		285
Consolidated	$	13,116	$	12,441	$	13,731
Income tax expense
Natural gas	$	1,336	$	1,283	$	843
Electric		546		666		565
Propane gas		110		245		130
Common		246		93		77
Consolidated	$	2,238	$	2,287	$	1,615

14.   Quarterly Financial Data (Unaudited)

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

(Dollars in thousands, except per share amounts):	First Quarter		Second Quarter		Third Quarter *		Fourth Quarter
2006
Revenues	$	43,348	$	29,878	$	29,415	$	31,752
Gross profit	$	14,135	$	11,402	$	10,867	$	12,018
Operating income	$	4,528	$	2,065	$	1,263	$	2,321
Earnings before income taxes	$	3,507	$	1,162	$	384	$	1,354
Net Income	$	2,221	$	738	$	335	$	875
Earnings per common share (basic and diluted):
Continuing operations	$	0.37	$	0.12	$	0.05	$	0.14
2005

Revenues	$	35,438	$	28,329	$	29,190	$	37,066
Gross profit	$	13,619	$	10,963	$	10,374	$	12,263
Operating income	$	4,684	$	2,215	$	1,578	$	2,160
Earnings before income taxes	$	3,711	$	1,205	$	573	$	1,046
Net Income	$	2,353	$	851	$	260	$	784
Earnings per common share (basic and diluted):
Continuing operations	$	0.40	$	0.14	$	0.04	$	0.13

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

Summary of Third Quarter 2006 Adjustment

(Dollars in thousands, except per share amounts):	Third Quarter Before Revision		Adjustment		Third Quarter  After Revision
2006
Revenues	$	29,415		-	$	29,415
Gross profit	$	10,867		-	$	10,867
Operating income	$	1,488		(225)	$	1,263
Earnings before income taxes	$	609		(225)	$	384
Net Income	$	475		(140)	$	335
Earnings per common share (basic and diluted):
Continuing operations	$	0.08		(.03)	$	0.05

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Directors and Shareholders of FPU:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Florida Public Utilities Company and its wholly-owned subsidiary, Flo-Gas Corporation as of December 31, 2006 and 2005 and the related consolidated statements of income, comprehensive income, common shareholders' equity and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Florida Public Utilities Company and its wholly-owned subsidiary, Flo-Gas Corporation at December 31, 2006 and 2005, and the results of its operation and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.  

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

BDO Seidman, LLP

Certified Public Accountants

West Palm Beach, Florida

March 16, 2007

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

None

Item 9A.   Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

Item 9B.   Other Information

None

PART III

Item 10.    Directors and Executive Officers of the Registrant

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

Item 11.   Executive Compensation

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

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

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

Item 13.   Certain Relationships and Related Transactions

None.

Item 14.   Principal Accountant Fees and Services

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

PART IV

Item 15.   Exhibits, Financial Statement Schedules

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

(1)   Financial Statements

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

Consolidated Statements of Income

Consolidated Statements of Comprehensive Income

Consolidated Balance Sheets

Consolidated Statements of Capitalization

Consolidated Statements of Common Shareholders' Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

(2)   Financial Statement Schedules

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

Allowance for Doubtful Accounts

(3)   Exhibits

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

31.1 Certification of Principal Executive Officer (302)

31.2 Certification of Principal Financial Officer (302)

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

#  Denotes management contract or compensatory plan or arrangement

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

SIGNATURES

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

FLORIDA PUBLIC UTILITIES COMPANY

       /s/ George M Bachman

George M Bachman, Chief Financial Officer

(Duly Authorized Officer)

Date: March 19, 2007

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

/s/ John T. English

Date:  March 19, 2007

John T. English

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

Director (Principal Executive Officer)

/s/ George M. Bachman

Date:  March 19, 2007

George M Bachman, Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)

/s/ Ellen Terry Benoit

Date:  March 19, 2007

Ellen Terry Benoit, Director

/s/ Richard C. Hitchins

Date:  March 19, 2007

Richard C. Hitchins, Director

/s/ Dennis S. Hudson III

Date:  March 19, 2007

Dennis S. Hudson III, Director

/s/ Paul L. Maddock, Jr.

Date:  March 19, 2007

Paul L. Maddock, Jr., Director

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

Troy W. Maschmeyer, Jr., Director

FLORIDA PUBLIC UTILITIES COMPANY

EXHIBIT INDEX

Regulation S-K

Item Number

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

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

31.1 Certification of Principal Executive Officer (302)

31.2 Certification of Principal Financial Officer (302)

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

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

EX-10

AGREEMENT FOR GENERATION SERVICES

BETWEEN

GULF POWER COMPANY

AND

FLORIDA PUBLIC UTILITIES COMPANY

Dated as of December 28, 2006

TABLE OF CONTENTS

APPENDIX A  CAPACITY PURCHASE

APPENDIX B  MONTHLY CAPACITY PAYMENT

APPENDIX C  GULF ENERGY RATE

APPENDIX D  MONTHLY ENERGY PAYMENT

APPENDIX E  FORM OF COMPLIANCE CERTIFICATE

AGREEMENT FOR GENERATION SERVICES

BETWEEN

GULF POWER COMPANY

AND

FLORIDA PUBLIC UTILITIES COMPANY

This Agreement for Generation Services (“Agreement”) is entered into and effective as of the 28th day of December 2006 (“Effective Date”), by and between GULF POWER COMPANY (acting through its agent, Southern Company Services, Inc., a corporation organized and existing under the laws of the State of Alabama (“SCS”)), a corporation organized and existing under the laws of the State of Florida (“Gulf Power”) and FLORIDA PUBLIC UTILITIES COMPANY, a corporation organized and existing under the laws of the State of Florida (“FPUC”).  Gulf Power and FPUC are individually referred to as a “Party” and collectively referred to as the “Parties.”

W I T N E S S E T H:

WHEREAS, Gulf Power is engaged in, among other things, the sale of electric power at wholesale for resale and has received authorization from FERC to provide such service at market-based rates in accordance with the Southern Operating Companies’ FERC Electric Tariff, Second Revised Volume No. 4, Market-Based Rate Tariff;

WHEREAS, FPUC supplies the native load electric requirements of its electric system headquartered in Marianna, Florida (“Northwest Division”); and

WHEREAS, subject to the terms and conditions of this Agreement, the Parties desire for Gulf Power to supply the native load electric requirements of the Northwest Division through FPUC’s purchase of capacity and associated energy pursuant to this Agreement.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein set forth, and other good and valuable consideration, the receipt, sufficiency and adequacy

of which are hereby acknowledged, each Party intending to be legally bound, hereby agrees as follows:

ARTICLE 1

DEFINITIONS & INTERPRETATION

1.1

Definitions.  In addition to the initially capitalized terms and phrases defined in the preamble of this Agreement, the following capitalized terms used herein and not otherwise defined, whether singular or plural, shall have the following respective meanings:

“AAA” shall have the meaning set forth in Section 16.2.2.

“Acceptable Rating” shall mean, with respect to a Person, such Person has: (A) (i) an issuer rating (and senior unsecured rating if also available) of at or above Baa3 (or future equivalent) by Moody’s, or (ii) an issuer credit rating (and senior unsecured rating if also available) of at or above BBB- (or future equivalent) by S&P; or (B) the Required Ratios but does not have an issuer credit rating or senior unsecured rating by S&P and does not have an issuer rating or senior unsecured rating by Moody’s.  

“Adjusted Hourly Demand” shall mean, for a given Hour, the sum of: (a) the Northwest Hourly Demand; plus (b) the amount of any demand satisfied by generation connected to the Northwest Division System (including distributed generation); plus (c) contract interruptible or curtailable load on such electric system curtailed at Gulf Power’s request and any firm load reductions occurring as a result of system emergencies; plus (d) transmission and other losses from the Delivery Point(s) that would be associated with the foregoing (b) and (c) as if such demand and loads (whether or not curtailed, interrupted or reduced) were served by Gulf Power under this Agreement (such transmission losses on the Transmission System to be determined pursuant to the then-current transmission tariff (or other applicable arrangement governing

transmission on the Transmission System) applicable to transmission service on the Transmission System, as amended from time to time), all expressed in megawatt-hours per hour (MWH/H).  In determining the total Northwest Hourly Demand for any Hour, the demand measurements at all applicable Meter Point(s) shall be cumulated simultaneously.  

“Affiliate” shall mean, with respect to any Person, any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person.  For purposes of this definition, “control” means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise.  The terms “controlling” and “controlled” have meanings correlative to the foregoing.

“After-Tax Basis” means, with respect to a specified amount owing or to be paid to any Person, such amount (“Base Amount”) supplemented by a further payment (“Additional Payment”) to that Person so that the sum of the Base Amount plus the Additional Payment shall, after deduction of the amount of all Federal, state and local income taxes required to be paid by such Person in respect of the receipt or accrual of the Base Amount and the Additional Payment (taking into account the net present value of any reduction in such income taxes resulting from tax benefits realized by the recipient as a result of the payment or the event giving rise to the payment), be equal to the amount required to be received.  Such calculations shall be made on the basis of the highest generally applicable Federal, state and local income tax rates applicable to the Person for whom the calculation is be ing made for all relevant periods, and shall take into account the deductibility of state and local income taxes for Federal income tax purposes.

“Agreement” shall mean this Agreement for Generation Services as set forth in the preamble above.

“Applicable Year” shall have the meaning set forth in Appendix C.

“Approval Deadline” shall have the meaning set forth in Section 9.4.

“Arbitration Expenses” shall have the meaning set forth in Section 16.5.

“Assignment Conditions” shall have the meaning set forth in Section 17.1.2.

“Banking Day” shall mean any Day other than a Saturday, Sunday or any Day on which the Federal Reserve Bank of New York is closed.

“Benefited Party” shall have the meaning set forth in Section 5.3.

“CAIR” shall mean the final rule issued by the Environmental Protection Agency on March 10, 2005 entitled “Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone,” often referred to as the Clean Air Interstate Rule, including any rules, regulations or other actions of any Governmental Authority(ies) to comply with or implement such rule.

“Calculation Year” shall have the meaning set forth in Appendix A.

“CAMR” shall mean the final rule issued by the Environmental Protection Agency on March 15, 2005 entitled “Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units,” often referred to as the Clean Air Mercury Rule, including any rules, regulations or other actions of any Governmental Authority(ies) to comply with or implement such rule.

“Capacity Purchase” shall have the meaning set forth in Appendix A.

“Cash Security” shall mean cash security, free and clear of any adverse lien or interest, pursuant to a pledge agreement in form and substance reasonably acceptable to the Party(ies) to which such security is being provided.

“Change in Law” means the adoption, enactment, promulgation or issuance of, a change in, or a new or changed interpretation by a Governmental Authority of, any Law or any standards

or criteria contained in a permit, license or other approval of a Governmental Authority after June 21, 2005.

“Change in Law Notice” shall have the meaning set forth in Section 9.1.2.

“Confidential Information” shall have the meaning set forth in Section 15.1.

“Continuation Period” shall have the meaning set forth in Section 9.5.2.

“Current Year” shall have the meaning set forth in Appendix C.

“Day” shall mean a calendar day; provided, however, for purposes of this Agreement, a Day shall begin and end at the applicable Operating Time.

“Decreased Costs” means the amount of any reduction in Gulf Power’s costs and/or expenses (fixed and variable)  that result from complying with or recognizing a Change(s) in Law and which: (i) is associated with any of Gulf Power’s generating and power supply resources; (ii) is associated with capacity and energy provided under this Agreement; or (iii) is realized by Gulf Power in performing its obligations under this Agreement; provided, however, with respect to any Decreased Costs under the foregoing (i), any benefit or credit that FPUC is entitled to receive as a result of such Decreased Costs shall be limited to a proportionate share based on the amount of capacity provided under this Agreement and FPUC’s actual load served under this Agreement. In no event shall Decreased Costs be reflected in a separate Change in Law Component pursuant to Section 9.1.3 if such Decrease d Costs are also reflected in the Gulf Energy Rate pursuant to the formula in Appendix C.  

“Defaulting Party” shall have the meaning set forth in Section 12.1.

“Delivered Energy” shall mean, for a given Hour, all energy (expressed in megawatt-Hours (MWH)) delivered by Gulf Power to FPUC under this Agreement at the Delivery Point(s), which energy shall be measured at the Meter Point(s) and shall be increased for transmission and

other losses from the Delivery Point(s) to the Meter Point(s), where such transmission losses on the Transmission System are to be determined pursuant to the then-current OATT (or other arrangement governing transmission on the Transmission System) applicable to transmission service on the Transmission System, as amended from time to time.

“Delivery Point(s)” shall mean (as applicable): (i) the high voltage side of the generator step-up transformer(s) at each of the generating units and plants from which capacity and energy are provided under this Agreement, if such units and/or plants are connected to the Transmission System; and/or or (ii) the interface(s) between the Transmission System and the system(s) to which the generating units and plants from which capacity and energy are provided under this Agreement are connected, if such units and/or plants are not connected to the Transmission System.

“Disallowance Order” shall have the meaning set forth in Section 9.5.1.

“Dispute Response” shall have the meaning set forth in Section 16.1.1.

“Disputing Party” shall have the meaning set forth in Section 16.1.1.

“Due Date” shall have the meaning set forth in Section 6.1.3.

“Effective Date” shall have the meaning set forth in the preamble of this Agreement.

“Eligible Collateral” shall mean an Eligible Letter of Credit, an Eligible Guaranty, or Cash Security.

“Eligible Guaranty” shall mean a continuing parent guaranty in form and substance reasonably acceptable to the receiving Party issued by an entity who has and maintains an Acceptable Rating.

“Eligible Letter of Credit” shall mean a letter of credit in form and substance reasonably acceptable to the receiving Party issued by a major U.S. commercial bank with assets of at least

$25 billion and a senior unsecured rating of at least A2 (or future equivalent) by Moody’s or at least A (or future equivalent) by S&P.  

“Event of Default” shall have the meaning set forth in Section 12.1.

“Federal Power Act” means the Federal Power Act, 16 U.S.C.A. §§ 791a-828c, as the same may hereafter be amended from time to time.

“FERC” shall mean the Federal Energy Regulatory Commission or any Governmental Authority succeeding to the powers and functions thereof under the Federal Power Act.

“Force Majeure Event” shall have the meaning set forth in Section 11.1.1.

“Forecasted Northwest Annual Peak Demand” shall mean the quantity determined pursuant to Appendix A of this Agreement.

“FPSC” shall mean the Florida Public Service Commission, or any Governmental Authority succeeding to the powers and functions thereof.

“FPSC Approval” shall have the meaning set forth in Section 9.4.1.

“FPUC Information” shall have the meaning set forth in Section 17.16.

“FPUC Liquidated Damages” shall have the meaning set forth in Section 12.3.3.

“FPUC Termination Date” shall have the meaning set forth in Section 12.3.2.

“FPUC” shall have the meaning set forth in the first paragraph of this Agreement.

“Funds From Operations Interest Coverage Ratio” shall mean, with respect to a Party, the sum of such Party’s Net Income from Continuing Operations plus Depreciation and Amortization plus Deferred Income Taxes plus gross interest expense incurred before subtracting capitalized interest and interest income divided by such Party’s gross interest expense incurred before subtracting capitalized interest and interest income.  All items included in the calculation

of the Funds From Operations Interest Coverage Ratio shall be prepared and calculated in accordance with GAAP.

“GAAP” means generally accepted accounting principles in the United States applied on a consistent basis.

“Governmental Authority” means any federal, state, local, territorial or municipal government and any department, commission, board, court, bureau, agency, instrumentality, judicial or administrative body thereof.

“Growth Rate” shall have the meaning set forth in Appendix A.

“Guarantor” shall mean, with respect to a Party, an entity that guarantees such Party’s obligations under this Agreement, including through an Eligible Guaranty.

“Gulf Energy Rate” shall have the meaning set forth in Appendix C.

“Gulf Liquidated Damages” shall have the meaning set forth in Section 12.4.3.

“Gulf Power” shall have the meaning set forth in the preamble of this Agreement.

“Gulf Termination Date” shall have the meaning set forth in Section 12.4.2.

“Harmed Party” shall have the meaning set forth in Section 5.3.

“Hour” shall mean one (1) of the clock-hours of a Day.

“Hourly” shall have a meaning correlative to that of Hour.

“Impacted Party” shall have the meaning set forth in Section 9.3.1.

“Impasse Notice” shall have the meaning set forth in Section 16.1.2.

“Increased Costs” means the additional costs and expenses (fixed and variable)  incurred by Gulf Power that result from complying with or recognizing a Change(s) in Law and which: (i) are associated with any of Gulf Power’s generating and power supply resources; (ii) are associated with capacity and energy provided under this Agreement; or (iii) are incurred by Gulf

Power in performing its obligations under this Agreement; provided, however, with respect to any Increased Costs under the foregoing (i), FPUC’s responsibility for such costs shall be limited to a proportionate share based on the amount of capacity provided under this Agreement and FPUC’s actual load served under this Agreement.  Examples of Increased Costs shall include costs and expenses resulting from:  (i) compliance with environmental Laws changing existing emissions limits (e.g., NOx) or establishing limits for currently uncontrolled substances (e.g., CO2 and mercury); (ii) the imposition of or increases in taxes (such as taxes on power and gas sales) except for income taxes; and (iii) compliance with health and safety Laws.  For purposes of calculating the Increased Costs associated with capitalized additions or modifications or other capital expenditures (determin ed in accordance with GAAP), the Parties will at that time jointly establish an appropriate annual fixed charge rate for application to the original capital cost (less depreciation) of such additions, modifications, or other capital expenditures.  Such fixed charge rate shall be consistent with the methodology and approach used by the FPSC to determine the weighted average cost of capital (otherwise known as the overall rate of return) for the purpose of establishing prices for retail electricity service provided by Gulf Power.  This calculation will represent the total cost associated with the identified addition, modifications, or other capital expenditures including and recognizing the key factors such as depreciation, useful life, carrying costs, and any other cost or expense item directly related to capital investments.  Any costs and/or expenses not otherwise reflected in a fixed charge rate calculation shall be treated as Increased Costs as incurred; provided, however, that in no event shall Increased Costs be reflected in a separate Change in Law Component pursuant to Section 9.1.3 if such Increased Costs are also reflected in the Gulf Energy Rate pursuant to the formula in Appendix C.

“Incremental Benefit” shall have the meaning set forth in Section 5.3.

“Incremental Burden” shall have the meaning set forth in Section 5.3.

“Indemnified Party” shall have the meaning set forth in Section 10.1.4.

“Indemnifying Party” shall have the meaning set forth in Section 10.1.4.

“Interest Rate” shall mean the rate per annum equal to the lesser of: (i) the highest interest rate allowed by Law; or (ii) (a) for the first 14 Days of a given consecutive period of time during which interest shall accrue under this Agreement at the Interest Rate, the prime rate as stated in the Wall Street Journal on the date payment is due; and (b) for the remainder of such consecutive period of time after such 14 Day period has expired, two percent (2%) plus the prime rate as stated in the Wall Street Journal on the date payment is due.

“Law” means any act; statute; law; requirement; ordinance; order; ruling or rule; regulation; standards and/or criteria contained in any permit, license or other approval; legislative or administrative action; or a decree, judgment or order of any Governmental Authority imposed, whether in effect now or at any time in the future.

“Meter Point(s)” shall mean the points of interconnection between the Northwest Division System and the Transmission System.

“Month” shall mean a calendar month.

“Monthly” shall have a meaning correlative to that of Month.

“Monthly Capacity Payment” shall have the meaning set forth in Section 4.1.

“Monthly Capacity Rate” shall mean, for each Month during the Service Term, the applicable rate per kilowatt Month ($/kW-Mo.) for the Year in which such Month occurs, determined pursuant to the following table:

Year	Capacity Rate ($/kW-Mo.)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017

“Monthly Energy Payment” shall have the meaning set forth in Section 4.2.

“Moody’s” shall mean Moody’s Investors Service or its successor, provided that, if  Moody’s ceases to exist or publish ratings, Moody’s shall mean a nationally recognized rating agency mutually agreed upon by the Parties, which agreement will not be unreasonably withheld or delayed.

“Negotiation Period” shall have the meaning set forth in Section 16.1.2.

“NERC” shall mean the North American Electric Reliability Council, including the regional reliability organization(s) to which the Southern Operating Companies belong, and any successor organization(s).

“Non-Defaulting Party” shall have the meaning set forth in Section 12.1.

“Northwest Annual Peak Demand” shall mean the amount of the Adjusted Hourly Demand for the Northwest Division for the one Hour period during the Peak Season in which the Northwest Division experiences the highest Adjusted Hourly Demand.

“Northwest Division” shall have the meaning set forth in the preamble of this Agreement.

“Northwest Division System” shall mean the integrated transmission and/or distribution system of the Northwest Division, as such system may be modified or expanded from time-to-time, as well as any successor transmission and/or distribution system(s).

“Northwest Hourly Demand” shall mean, for a given Hour, the sum of: (i) the integrated Hourly energy requirements for the Northwest Division expressed in kilowatt-Hours per Hour (kWH/H), as measured conjunctively at the Meter Point(s), plus: (ii) transmission and other losses from the Delivery Point(s) to the Meter Point(s) that would be associated with such demand (such transmission losses on the Transmission System to be determined pursuant to the then-current OATT (or other arrangement governing transmission on the Transmission System) applicable to transmission service for the Transmission System, as amended from time to time).

“Notice of Dispute” shall have the meaning set forth in Section 16.1.1.

“OATT” shall mean the Open Access Transmission Tariff governing transmission service on the Transmission System, as such tariff is filed at FERC and as such tariff may be revised or amended from time to time.

“Operating Time” shall mean the time standard used to dispatch, schedule and control generation in the Southern Control Area (currently, central prevailing time).

“Original Amount” shall have the meaning set forth in Section 9.3.1.

“Party-Appointed Arbitrators” shall have the meaning set forth in Section 16.2.1.

“Peak Season” shall mean the period of time comprising the Months of May through September.

“Person” means any individual, corporation, limited liability corporation, partnership, joint venture, trust, unincorporated organization, Governmental Authority, municipal, city or other entity.

“Previous Season” shall have the meaning set forth in Appendix A.

“Previous Year” shall have the meaning set forth in Appendix C.

“Proposed Resolutions” shall have the meaning set forth in Section 16.3.

“Prudent Utility Practices” shall mean, at a particular time, any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry prior to such time, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired results at a reasonable cost consistent with good business practices, reliability, safety and expedition.  Prudent Utility Practices is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be a spectrum of possible practices, methods or acts, having due regard for, among other things, manufacturers’ warranties and the requirements of Governmental Authorities of competent jurisdiction and the requirements of this Agreement.

“Required FPUC Collateral Amount” shall be equal to the aggregate Monthly Capacity Payments as calculated in Appendix B hereto that are reasonably expected to become due under this Agreement (as reasonably calculated by Gulf Power (assuming no Event of Default has occurred or will occur hereunder and no termination or modification of this Agreement will occur)) during the 12 Months immediately following the date the Required FPUC Collateral Amount is determined by Gulf Power from time to time; provided, however, before the commencement of the Service Term, the Required FPUC Collateral Amount shall be the aggregate Monthly Capacity Payments as calculated in Appendix B hereto that are reasonably expected to become due under this Agreement (as reasonably calculated by Gulf Power (assuming no Event of Default has occurred or will occur hereunder and no termination or

modification of this Agreement will occur)) for the first 12 Months of the Service Term;   provided, further, upon the expiration of the Service Term and until all amounts under this Agreement that will be due to be paid by FPUC are indefeasibly paid (including all true-up amounts after the expiration of the Service Term under Appendix C), the Required FPUC Collateral Amount shall be equal to the Monthly Capacity Payment for the final Month of the Service Term (regardless of whether such capacity payment has been paid).

“Required Gulf Collateral Amount” shall be equal to the aggregate Monthly Capacity Payments as calculated in Appendix B hereto that are reasonably expected to become due under this Agreement (as reasonably calculated by Gulf Power (assuming no Event of Default has occurred or will occur hereunder and no termination or modification of this Agreement will occur)) during the 12 Months immediately following the date the Required Gulf Collateral Amount is determined by Gulf Power from time to time; provided, however, before the commencement of the Service Term, the Required Gulf Collateral Amount shall be the aggregate Monthly Capacity Payments as calculated in Appendix B hereto that are reasonably expected to become due under this Agreement (as reasonably calculated by Gulf Power (assuming no Event of Default has occurred or will occur hereunder and no termination or modification of this Agreement will oc cur)) for the first 12 Months of the Service Term.

“Required Ratios” means a Funds From Operations Interest Coverage Ratio of at least 2.0 and a Total Debt to Total Capital Ratio not to exceed .65, as tested quarterly as of the end of each quarter averaged over the 6 consecutive quarters then ending.

“Reserve Requirement” means fifteen percent (15%).

“RTO” shall have the meaning set forth in Section 5.3.

“S&P” means Standard & Poor’s, a division of The McGraw-Hill Companies, Inc., or its successor, provided that, if S&P ceases to exist or publish ratings, S&P shall mean a nationally recognized rating agency mutually agreed upon by the Parties, which agreement will not be unreasonably withheld or delayed.

“SCGen” shall have the meaning set forth in Section 17.16.

“SCS” shall have the meaning set forth in the preamble of this Agreement.

“SEC” shall have the meaning set forth in Section 15.2.3.

“Service Term” shall have the meaning set forth in Section 2.1.

“Southern Company” shall mean The Southern Company, a Delaware corporation.

“Southern Control Area” shall mean the electric service area encompassed by tie lines, including, the pseudo tie lines (as defined in NERC’s “Terms Used in the Policies”), between the Southern Operating Companies and other utilities.

“Southern Operating Companies” shall mean, collectively, the electric utility operating company Affiliates of Southern Company engaged in common dispatch and control of generating resources within the Southern Control Area, which, as of the Effective Date, include Alabama Power Company, Georgia Power Company, Gulf Power, Mississippi Power Company, and Southern Power Company.

“Tariff” shall mean Southern Operating Companies’ FERC Electric Tariff, Second Revised Volume No. 4, Market-Based Rate Tariff, as superseded or amended from time to time.

“Term” shall mean the period of time commencing on the Effective Date and ending December 31, 2017 as set forth in Article 2.

“Third Arbitrator” shall have the meaning set forth in Section 16.2.1.

“Total Debt to Total Capital Ratio” shall mean, with respect to a Party, such Party’s Long Term Debt plus Current Maturities plus Commercial Paper plus Other Short Term Borrowings divided by such Party’s Long Term Debt plus Current Maturities plus Commercial Paper plus Other Short Term Borrowings plus Shareholder’s Equity (Including Preferred) plus Minority Interest.  All items included in the calculation of the Total Debt to Total Capital Ratio shall be prepared and calculated in accordance with GAAP.

“Transmission Force Majeure Event” means the occurrence of a circumstance where: (i) a Force Majeure Event causes physical damage to transmission facilities; (ii) FPUC has procured firm transmission service or network integration transmission service under the OATT with respect to the energy to be supplied by Gulf Power under this Agreement; and (iii) as a result of such physical damage to transmission facilities, FPUC is unable to utilize such procured firm and/or network integration transmission service to deliver such energy from the Delivery Point(s) to the Meter Point(s).  Unless the circumstances in (i) through (iii) above exist, a curtailment or interruption of transmission service shall not constitute a Transmission Force Majeure Event.

“Transmission Risk” means the ramifications (performance, economic or otherwise) resulting from the unavailability of transmission service, including inadequacy, interruption or curtailment of transmission service.

“Transmission System” shall mean the integrated transmission systems of the electric utility operating companies of Southern Company, as such systems may be modified or expanded from time-to-time, as well as any successor transmission system(s).

“Year” shall mean a calendar year.

1.2

Interpretation. In this Agreement, unless the context otherwise requires, the singular shall include the plural and any pronoun shall include the corresponding masculine, feminine and neuter forms.  The words “hereof,” “herein,” “hereto” and “hereunder” and words of similar import when used in this Agreement shall, unless otherwise expressly specified, refer to this Agreement as a whole and not to any particular provision of this Agreement.  Whenever the terms “include” or “including” are used herein in connection with a listing of items included within a prior reference, such listing shall be interpreted to be illustrative only, and shall not be interpreted as a limitation on or exclusive listing of the items included within the prior reference.  Any reference in this Agreement to “Section,” “Article” or “Append ix” shall be references to this Agreement unless otherwise stated, and all such Appendices shall be incorporated in this Agreement by reference.  Unless specified otherwise, a reference to a given agreement or instrument, and all schedules, exhibits, appendices and attachments thereto, shall be a reference to that agreement or instrument as modified, amended, supplemented and restated, and in effect from time to time (subject to Section 17.19).

1.3

Construction.  Both Parties acknowledge that each was actively involved in the negotiation and drafting of this Agreement and that no Law or rule of construction shall be raised or used in which the provisions of this Agreement shall be construed in favor of or against either Party because one is deemed to be the author thereof.

ARTICLE 2

TERM OF THE AGREEMENT

2.1

Term.

This Agreement shall begin on the Effective Date and shall remain in effect for a term ending at the end of the Day on December 31, 2017 (“Term”), unless this Agreement is terminated earlier in accordance with its terms.  The Service Term under this

Agreement shall commence at the beginning of the Day (Operating Time) on January 1, 2008 and shall continue until the expiration or termination of this Agreement in accordance with its terms.

2.2

Survival.  All provisions of this Agreement that expressly or by implication come into or continue in force and effect following the expiration or termination of this Agreement shall remain in effect and be enforceable following such expiration or termination.

ARTICLE 3

SALE OF ELECTRIC CAPACITY AND ENERGY

3.1

Sale and Supply of Capacity.  During the Service Term, subject to the terms of this Agreement, Gulf Power shall supply and sell to FPUC, and FPUC shall receive and purchase from Gulf Power, an amount of capacity equal to the Capacity Purchase as determined in accordance with the methodology provided in Appendix A.

3.2

Sale and Delivery of Energy.  During the Service Term, subject to the terms of this Agreement, Gulf Power shall sell and deliver to FPUC, and FPUC shall receive and purchase from Gulf Power, a supply of energy necessary to supply the Northwest Hourly Demand.  Gulf Power shall deliver such energy to, and FPUC shall receive such energy at, the Delivery Point(s).

3.3

Supply Sources for Energy.  FPUC acknowledges and agrees that Gulf Power, or its agent(s), shall have the sole authority, which Gulf Power or its agent(s) may exercise in their sole discretion, to manage, control, operate and maintain the electricity resources used to supply energy to FPUC under this Agreement.  Gulf Power may serve FPUC with energy from any resource(s) available to it.  Gulf Power shall use the same method of dispatching resources to provide energy to FPUC under this Agreement as it uses for all of its territorial customers and shall make no adverse distinction against FPUC in designating resources to provide energy to FPUC hereunder.  In addition, Gulf Power will assist FPUC in identifying resources associated

with this Agreement as may be required in connection with FPUC’s obtaining network integration transmission service under the OATT.    

3.4

Exclusive Supply.  FPUC shall not purchase electric energy or capacity to meet the Northwest Division’s load requirements from any party other than Gulf Power without the prior written consent of Gulf Power except to the extent that: (i) Gulf Power fails to furnish energy or capacity to FPUC in accordance with the terms of this Agreement; (ii) FPUC is required to purchase energy and/or capacity from third party generating facilities directly connected to the Northwest Division System pursuant to the Public Utility Regulatory Policies Act of 1978 (including regulations issued thereunder); and/or (iii) another Law requires FPUC to meet some portion of its load requirements by purchasing a required amount of energy (MWh) and/or capacity (MW) from third party generators.  Provided, however, in the event that (ii) or (iii) of the foregoing sentence is applicable, FPUC shall provide Gulf Power with prompt notice of the applicable requirement to purchase capacity and/or energy from third party generating facilities.  If such notice is provided, the Parties shall promptly commence good faith negotiations to agree upon feasible actions, if any, to be taken by either or both Parties that would facilitate the means by which FPUC can satisfy and/or comply with such requirement while simultaneously leaving this Agreement in full force and effect as originally executed.  In the event that the Parties cannot agree upon such actions, FPUC and Gulf Power shall negotiate an appropriate amendment to this Agreement to reduce the amount of capacity and/or energy (as applicable) purchased under this Agreement, but only to the extent necessary for FPUC to comply with the specific requirement to purchase capacity and/or energy from the applicable third parties; provided, however, the recognition of such requirement in any such amendment and the reduction of the amount of capacity and/o r energy purchased shall not adversely distinguish

against Gulf Power or this Agreement as compared to FPUC’s other power suppliers and/or other power supply arrangements, unless such adverse distinction is required by Prudent Utility Practices because of transmission considerations.  Any such amendment shall, to the maximum extent practicable, allow each Party to continue to recognize the economic bargain originally contemplated by this Agreement as of the Effective Date.  In addition, any such amendment shall define the use and control of any third party generating facilities, including reliability provisions, such that Gulf Power can continue to meet its obligations under Section 7.2.               

ARTICLE 4

PAYMENTS

4.1

Monthly Capacity Payment.  FPUC shall pay Gulf Power, or Gulf Power’s designated agent, a Monthly Capacity Payment for each Month of the Service Term, as calculated pursuant to the methodology in Appendix B.    

4.2

Monthly Energy Payment.  FPUC shall pay Gulf Power, or Gulf Power’s designated agent, a Monthly Energy Payment for each Month of the Service Term, as calculated pursuant to the methodology in Appendix D.

4.3

Other Payments.   In addition to the payments specified in this Article 4, each of FPUC and Gulf Power shall pay all amounts for which it is responsible pursuant to the other provisions of this Agreement.    

ARTICLE 5

TRANSMISSION

5.1

Transmission Arrangements.  

5.1.1

FPUC shall be responsible for all costs associated with and for making all necessary transmission arrangements (including any required ancillary services) for the

delivery of all Delivered Energy from and beyond the Delivery Point(s).  Such transmission arrangements (including the procurement of ancillary services) shall be made by FPUC pursuant to the provisions of the OATT.  Gulf Power shall be responsible for all costs associated with and for making all necessary transmission arrangements (including any required ancillary services) for the delivery of all Delivered Energy prior to the Delivery Point(s).  In the event that a Party is assessed costs that are the responsibility of the other Party pursuant to this Section 5.1.1, the responsible Party shall promptly reimburse the assessed Party for such costs actually incurred.     

5.1.2

Gulf Power shall, at no additional cost to Gulf Power, provide such administrative assistance to FPUC as it may reasonably request consistent with applicable Law in connection with FPUC’s application for network integration transmission service under the OATT for Delivered Energy purchased hereunder; provided, however, that FPUC acknowledges that it is solely responsible for requesting and contracting for such service (including the negotiation of all terms and conditions of the pertinent transmission agreements).

5.2

Transmission Risk.  Notwithstanding any other provision of this Agreement, any and all Transmission Risk associated with energy to be scheduled and/or delivered at and beyond the Delivery Point(s) in connection with this Agreement, whether before or after the Meter Point(s), shall be expressly borne by FPUC. In no event shall Gulf Power or any of Gulf Power’s Affiliates be responsible or have any liability to FPUC whatsoever under this Agreement in connection with, and in no event shall the Monthly Capacity Payment (subject to Section 11.1.3.2) be reduced as a result of, the unavailability, inadequacy, interruption or curtailment of transmission service (whether before or after the Meter Point(s)) for any energy to be delivered

hereunder.

5.3       Formation of RTO.  In the event that a Regional Transmission Organization(s) or similar organization (“RTO”) is formed and the formation and/or implementation of such RTO results in: (i) a quantifiable monetary benefit for a Party with regard to its performance under this Agreement (“Benefited Party”) that is greater than the monetary benefit to such Party contemplated on the Effective Date (the amount by which such monetary benefit is increased being referred to as the “Incremental Benefit”); and (ii) a quantifiable monetary harm for the other Party with regard to its performance under this Agreement (“Harmed Party”) that results in a monetary burden to such Party that is greater than the monetary burden to such Party contemplated on the Effective Date (the amount by which such monetary burden is in creased being referred to as the “Incremental Burden”), the Parties shall negotiate to reach mutual agreement regarding an amendment(s) to this Agreement establishing a method whereby the Benefited Party would share with the Harmed Party an amount of the Incremental Benefit equal to the lesser of: (i) the Incremental Benefit; or (ii) the Incremental Burden.  In no event shall such amendment(s) require the Benefited Party to bear more of a monetary burden or receive less of a monetary benefit than as originally contemplated in this Agreement for such Party on the Effective Date.

ARTICLE 6

BILLING AND PAYMENT

6.1

Billing and Payment.

6.1.1

As promptly as practicable after the end of each Month during the Service Term, but no later than the tenth (10th) Day of the following Month, Gulf Power or its agent shall send FPUC an invoice stating the Monthly Capacity Payment, the Monthly

Energy Payment and any other amounts for which FPUC is responsible under this Agreement.

6.1.2

In addition to the payments set forth in Section 6.1.1, the Monthly invoice shall include the following adjustments: (a) billing corrections, including charges or credits, identified by either of the Parties subsequent to the last Monthly invoice, which shall not be subject to interest; (b) any billing corrections, including charges or credits, that the Parties have mutually agreed upon or otherwise resolved in accordance with Section 6.2 subsequent to the last Monthly invoice, which shall be subject to interest in accordance with Section 6.2; and (c) any overdue amounts, which shall be subject to interest in accordance with Section 6.2.  Any corrections made by Gulf Power pursuant to subpart (a) of the foregoing sentence to a charge set forth on a particular Monthly invoice shall be made by Gulf Power no later than 365 Days after the issuance of such invoice.  Notwithstanding the foregoin g, the adjustments contemplated by this Section 6.1.2 shall not include true-ups made pursuant to the calculation of the Gulf Energy Rate under Appendix C.

6.1.3

Each Monthly payment shall be due and payable on or before the tenth (10^th) Day after FPUC’s receipt of each Monthly invoice or if such Day is not a Banking Day, the next Banking Day (“Due Date”).  FPUC shall make payment to Gulf Power or its designated agent in accordance with such invoices on or before the Due Date in immediately available funds through wire transfer of funds or other means acceptable to Gulf Power.  If FPUC does not make a payment on or before the Due Date, then interest shall be added to the overdue payment, from the date such overdue payment was due until

such overdue payment together with interest is paid, which interest shall be compounded Monthly at the Interest Rate.

6.2

Billing Disputes and Final Accounting.

6.2.1

If, after receiving a Monthly invoice (or any other statement or bill), FPUC reasonably questions or contests the amount or propriety of any payment or amount claimed by Gulf Power to be due pursuant to this Agreement, FPUC shall provide Gulf Power with written notice of such disputed invoice amount.  Notwithstanding the notice of a disputed invoice amount, FPUC shall make payments in full in accordance with such disputed invoice and adjustments with interest shall subsequently be made, if appropriate, as set forth below.

6.2.2

FPUC shall have 12 Months after the receipt of any Monthly invoice (or any other statement or bill) to question or contest the amount or propriety of any charge or credit on such invoice or statement.  In the event that FPUC questions or contests any such charge or credit, Gulf Power shall promptly review the questioned charge or credit and shall notify FPUC of any error in the determination of amounts reflected on such disputed invoice and the amount of any adjusted payment that either Party is required to make as a result of such re-determination.  The Party required to make such payment shall make payment to the other Party in immediately available funds by the later of: (i) 10 Days after receipt by FPUC of any such notice of re-determination from Gulf Power as to the adjusted amount; or (ii) the Due Date for the next Monthly invoice.  Payments made by a Party under this Section 6. 2.2 shall include interest at the Interest Rate from the date the original payment was due until the date such payment together with interest at the Interest Rate is made.

6.3

Availability of Records.  Until the end of 12 Months after the receipt of any Monthly invoice, each Party will make available to the other Party and each Party may audit, such books and records of the other Party (or other relevant information to which such Party has access) as are reasonably necessary for such Party to calculate and determine the accuracy of amounts shown on such invoice and thereby to verify the appropriateness of the invoiced amounts.  Upon written request and reasonable notice, each Party will make available to the other Party copies of or access to such books and records during normal business Hours, at such requesting Party’s sole expense for purposes of conducting such an audit.  In the event either Party determines that an invoice was not accurate or appropriate, it shall notify the other Party in writing of the discrepancy and of the necessary correction.  The Party receiving such notice shall make such payments or take such other actions as are necessary to correct the discrepancy by the later of: (i) 10 Days following receipt of such notice; or (ii) the Due Date for the next Monthly invoice.

ARTICLE 7

CHARACTER OF SERVICE

7.1

Service Rendered.  This Agreement is intended as a service agreement pursuant to the Tariff.  Gulf Power shall provide and FPUC shall pay for services under this Agreement pursuant to the terms and conditions of the Tariff and of this Agreement.  To the extent the terms and conditions of the Tariff are inconsistent with those set forth in this Agreement, the provisions of this Agreement shall control.

7.2

Constancy of Supply.

7.2.1

Gulf Power shall supply energy to meet the load requirements of the Northwest Division in a manner that is as firm as, and otherwise comparable with, the

manner in which the Southern Operating Companies meet their firm retail native load requirements, without any adverse distinction; provided, however, notwithstanding any other provision of this Agreement, Gulf Power does not guarantee or warrant that Gulf Power will supply a constant or uninterrupted supply of energy under this Agreement; provided, further, that Gulf Power shall use commercially reasonable best efforts, consistent with Prudent Utility Practices and the provisions of this Agreement, to provide the services contemplated herein in an uninterrupted fashion.

7.2.2

Subject to Section 7.2.1, to the extent practicable and consistent with Prudent Utility Practices, Gulf Power shall raise or lower the output of the generating resources used to provide energy hereunder as necessary to follow the moment-by-moment changes in the sum of the total load requirements of the Northwest Division.  Gulf Power shall also provide FPUC with on-line and quick-start generation reserves consistent with the amount of capacity purchased under this Agreement.

7.2.3

Notwithstanding any other provision of this Agreement, in the event that  Gulf Power, or one of its respective agents, determines in its sole discretion that it is necessary or appropriate for Gulf Power to shed, interrupt, or curtail firm territorial requirements load (including for reason that adequate resources are not available), and Gulf Power does shed, interrupt or curtail such loads, then FPUC’s similar firm loads or interruptible/curtailable loads at the Northwest Division shall share in such interruption, curtailment or load shedding on a load-ratio basis and without adverse distinction.  FPUC may restore service to such shed, interrupted or curtailed loads consistent with the restoration of service to Gulf Power’s similar firm or interruptible/curtailable loads. For actions taken pursuant to this Section 7.2.3, neither Gulf Power, nor its Affiliates shall be

in breach of this Agreement by reason of, and shall have no liability whatsoever to FPUC for, any failure to make capacity available hereunder, or for any failure to deliver or any interruption in the delivery of energy hereunder or for any deficiency in the quality of service hereunder.  

7.3

Character of Transactions.  The sale of capacity by Gulf Power under this Agreement shall not constitute either: (i) a sale, lease, transfer or conveyance of an ownership interest or contractual right in or to any specific generation facility or resources; or (ii) a dedication of ownership or an entitlement to the capacity or output of any specific generation facility or resource.  

ARTICLE 8

METERING

8.1  

Metering.  

8.1.1 The amount of energy transferred under this Agreement shall be determined by meters selected by Gulf Power or other methods as Gulf Power and FPUC jointly deem necessary.  FPUC shall be responsible for and shall pay, under this Agreement, all costs of purchasing, installing, owning, reading, testing, inspecting, operating and maintaining the meters used in connection with service to FPUC under this Agreement (including meters owned by Gulf Power) to the extent that such costs are not otherwise assigned to or payable by another party under FPUC’s network operating agreement under the OATT.  Such costs shall be paid by FPUC in addition to the Monthly Capacity Payment and the Monthly Energy Payment.  The Parties shall cause meters to be read Monthly at times mutually agreed upon.  Metering records shall be available at all times to authorized agents and employees of the P arties for the purposes of this Agreement.

8.1.2

Each meter used in determining the demand for or amount of electric energy supplied hereunder will be tested, calibrated, repaired and corrected at the times and in a manner consistent with the provisions of FPUC’s network operating agreement under the OATT governing the meters that measure the delivery of energy to the Northwest Division load.  

8.1.3

The results of all such tests and calibrations shall be open to examination by FPUC and a report of every test shall be furnished to FPUC as soon as reasonably practical.  Any meters tested and found to be not more than 2% above or below normal shall be considered, solely for purposes of this Agreement, to be correct and accurate insofar as correction of billing is concerned.  If as a result of any test, any meter is found to register in excess of 2% either above or below normal, then, solely for purposes of this Agreement, the readings of such meter previously taken for billing purposes shall be corrected according to the percentage of inaccuracy so found, but no such correction shall extend beyond 90 days previous to the day on which the inaccuracy is discovered by such test.

8.1.4

For any period that a meter is found to have failed to register, then solely for purposes of this Agreement, it shall be assumed that the demand established, or electric energy delivered, as the case may be, during said period is the same as that for a period of like operation to be agreed upon by Gulf Power and FPUC during which such meter was in service and operating.

8.1.5

The provisions of this Article 8 shall apply only with respect to metering under this Agreement and shall have no application with respect to FPUC’s network operating agreement under the OATT.

ARTICLE 9

CHANGE IN LAW; ENVIRONMENTAL PROVISIONS; REGULATORY

9.1

Change in Law.  

9.1.1

Notwithstanding any other provision of this Agreement, but subject to Sections 9.1.2, 9.1.3 and 9.1.4 (including provision of the applicable Change in Law Notice): (i) FPUC shall pay Increased Costs (on an After-Tax Basis) through the Change in Law Component each Month pursuant to Section 9.1.3; and (ii) FPUC shall receive the benefit of Decreased Costs through the Change in Law Component each Month pursuant to Section 9.1.3.

9.1.2

At any time, Gulf Power may notify FPUC, or FPUC may notify Gulf Power, that a Change in Law will result or has resulted in: (i) Increased Costs that are FPUC’s responsibility under this Agreement; or (ii) Decreased Costs for which FPUC is entitled to receive a credit under this Agreement (“Change in Law Notice”).  The Change in Law Notice shall include: (x) the applicable Change in Law that has caused or will cause the Increased Costs or Decreased Costs; and (y) as applicable, the resulting Increased Costs that are FPUC’s responsibility hereunder or the resulting Decreased Costs for which FPUC is entitled to receive a credit (or a projection of such costs if actual costs cannot reasonably be known).  Such notice shall also include reasonable documentation of the applicable Change in Law and resulting Increased Costs or Decreased Costs.  Within 90 Days after a Part y receives a Change in Law Notice applicable to it, such Party shall: (a) make a good faith determination of whether the Increased Costs or Decreased Costs (as applicable) result from a Change in Law as specified in this Agreement; (b) make a good faith determination of whether the Increased

Costs or Decreased Costs (as applicable) are determined in accordance with this Agreement; and (c) send the Party providing the Change in Law Notice written notice of its determination.  In the event that a Party receiving a Change in Law Notice applicable to it does not send written notice of its determination within such time period, such Party shall be deemed to have concurred that the specified Increased Costs or Decreased Costs result from a Change in Law.  If such Party does not concur, the Parties shall commence discussions in an effort to address and resolve the basis for the disagreement.  If the Parties are unable to resolve their disagreement within 120 Days after the Change in Law Notice was received, the Parties shall submit the issue to binding arbitration under the procedures set forth in Article 16.  

9.1.3

  If a Party has provided a Change in Law Notice, Gulf Power shall initiate a Change in Law Component (or modify an existing Change in Law Component) as a separate and distinctly observable component of the Monthly invoices sent to FPUC hereunder that shall reflect Increased Costs that are FPUC’s responsibility or Decreased Costs for which FPUC is entitled to a credit (whether such costs are for future or prior periods); provided, however, if there is a disagreement with respect to whether a Change in Law has occurred or the amount of Increased Costs or Decreased Costs, the Change in Law Component shall reflect the position of Gulf Power with respect to Increased Costs and the position of FPUC with respect to Decreased Costs and then be resolved under the provisions of Article 16, Dispute Resolution, of this Agreement; provided, further, that to the extent any disagreement with regard to Increased Costs or Decreased Costs is resolved in a Party’s favor, then a payment shall be made to the applicable Party(ies) if required in order to refund or pay any overcharges or undercharges with appropriate interest, where

the amount of interest is to be calculated in accordance with the Interest Rate.  As applicable, FPUC shall pay or receive a credit for the amount of the Change in Law Component, as adjusted from time to time, with each Monthly invoice.  In the event that the Change in Law Component is based on an estimate of Increased Costs or Decreased Costs, there shall be included a true-up amount in a subsequent Monthly invoice (either a credit or an additional charge, as appropriate) to reflect actual Increased Costs or Decreased Costs once they are known. Any portion of a Change in Law Component that is for the recovery of Increased Costs or Decreased Costs incurred in prior periods shall include interest on such amounts at the Interest Rate.

9.1.4

Notwithstanding anything to the contrary in this Section 9.1 above, to the extent that Gulf Power includes Increased Costs and/or Decreased Costs in the calculation of the Gulf Energy Rate, (i) Sections 9.1.1, 9.1.2 and 9.1.3 shall not apply with respect to such costs or the Change(s) in Law associated with such costs, and (ii) FPUC shall pay or receive the benefit of (as applicable) such increases or decreases in costs through the Gulf Energy Rate and the Monthly Energy Payment as calculated by Gulf Power.      

9.2

Clean Air Interstate Rule and Clean Air Mercury Rule.  The Parties acknowledge that CAIR and/or CAMR impose obligations that will increase Gulf Power’s costs of providing capacity and energy under this Agreement.  Therefore, FPUC agrees to reimburse Gulf Power for an appropriate pro rata share (i.e., a proportionate share based on the amount of capacity provided under this Agreement and FPUC’s actual load served under this Agreement) of all costs and expenses incurred by Gulf Power that result from complying with or recognizing CAIR and CAMR with respect to Gulf Power’s generating and other power supply resources, including costs and expenses associated with obtaining emissions allowances, variable and fixed operation

and maintenance costs, and costs and expenses associated with making capital additions to or installing environmental controls at such resources.  Except to the extent that Gulf Power includes FPUC’s pro rata share of such costs and expenses in the Gulf Energy Rate, such pro rata share of such costs and expenses shall be calculated in the same manner as Increased Costs and shall be invoiced by Gulf Power and paid by FPUC through the Change in Law Component.  In addition, Gulf Power shall provide FPUC an appropriate pro rata share of the benefit of all allowances (if any) allocated by any Governmental Agency under CAIR and CAMR to Gulf Power’s generating resources, and allowances purchased by Gulf Power and its agent(s) for Gulf Power’s generating resources to comply with CAIR and CAMR, provided that FPUC shall not receive such benefit after the expiration of the Service Term.

9.3

Federal Energy Regulatory Commission.

9.3.1

The Parties anticipate that this Agreement is not required to be filed and accepted by FERC because it is a market-based contract.  Therefore, this Agreement shall not be contingent on FERC acceptance.  Having freely negotiated and agreed upon the economic bargain among them as set forth hereunder, the Parties waive all rights under Sections 205 and 206 of the Federal Power Act to effect a change in the Agreement.  Moreover, it is the Parties’ mutual intent that FERC be precluded, to the fullest extent permitted by law, from altering this Agreement in any way.  Notwithstanding the foregoing, if at any time FERC takes some action that adversely alters an amount(s) to be paid to a Party under this Agreement (the Party adversely affected by such action altering an amount(s) to be paid being referred to as the “Impacted Party”) as contemplated on the Effective Date (su ch amount(s) as contemplated on the Effective Date being referred to as the “Original Amount”), Impacted Party shall be deemed to have retained rights under

Section 205 and/or Section 206 (as applicable) to file for changes in the Agreement, but only to the extent required to modify this Agreement to more closely or entirely reflect the Original Amount.Moreover, in the event that FERC takes some action that adversely alters the Original Amount, Impacted Party may take any or all of the actions set forth under Section 9.3.1.1 and 9.3.1.2 in its sole and absolute discretion.

9.3.1.1

Impacted Party may exercise its Section 205 or Section 206 rights (as applicable) provided under Section 9.3.1 if at any time it reasonably determines in its sole discretion that it may be able to have this Agreement modified so that it more closely or entirely reflects the Original Amount.Before exercising such rights, Impacted Party shall negotiate with the other Party in an effort to reach mutual agreement regarding amendments to this Agreement so that it will more closely or entirely reflect the Original Amount.  Impacted Party shall file any resulting amendments for acceptance by FERC (if required by FERC), and the other Party shall not oppose such filing(s).  If the Parties are unable to agree upon such amendment(s), Impacted Party shall be entitled to make unilateral filing(s) at FERC under Section 205 or 206 (as applicable) to seek modificati on of this Agreement in order to more closely or entirely reflect the Original Amount.  In this latter event, the other Party shall not oppose Impacted Party’s right to restore the Original Amount (provided that the other Party shall retain the right to challenge the amount of and/or the methodology for calculating the Original Amount and/or the means by which the filing Party proposes to restore the Original Amount).  Any amendment(s) or filing(s) contemplated hereunder shall restore the Original Amount (or any allowed portion thereof) for the remainder of the Term and shall provide reimbursement to Impacted Party for any amounts that it overpaid or was underpaid (relative to the Original Amount) in

prior periods (with interest) as a result of the alteration of the Original Amount.  Such amendment(s) or filing(s) by Impacted Party shall not require the other Party to bear more of an economic burden than originally contemplated in this Agreement on the Effective Date.  Nothing in this Agreement is intended to or shall restrict the number of times that Impacted Party may exercise the above-described Section 205 and/or Section 206 rights during the Term or within any specific time frame.

9.3.1.2  If FERC takes some action that adversely alters the Original Amount and Impacted Party is Gulf Power, then Gulf Power shall be entitled to provide notice to FPUC that it is terminating this Agreement on a date that is no earlier than 365 Days after such notice is provided.  If: (i) FERC takes some action that adversely alters the Original Amount and Impacted Party is FPUC; (ii) FPUC has actively made reasonable efforts through negotiations with Gulf Power and has supported filings made at FERC by either Party to modify this Agreement so that it reflects the Original Amount; and (iii) FERC does not allow this Agreement to reflect the Original Amount within 120 Days after the first of such filings, then FPUC shall be entitled to provide notice to Gulf Power that it is terminating this Agreement on a date that is no earlier than 245 Days after such notice is provided.  If Impact ed Party provides a notice to terminate the Agreement under this Section, this Agreement shall terminate on the date specified in the applicable notice. Upon any such termination, no Party shall have any further liability or obligation under this Agreement to any other Party, except for any liabilities and obligations accruing prior to such termination.  

9.4

Initial Approval of the Florida Public Service Commission.  

9.4.1

No later than 45 Days after the Effective Date, FPUC shall make a filing with the FPSC seeking approval by the FPSC for FPUC to recover from its Northwest Division customers all payments required to be made to Gulf Power under this Agreement without material modification or condition with respect to such Agreement (“FPSC Approval”).  After making such filing, FPUC shall utilize diligent efforts to obtain the FPSC Approval by no later than July 1, 2007 (“Approval Deadline”).  FPUC shall promptly notify Gulf Power when it receives a ruling from the FPSC regarding the requested FPSC Approval.  FPUC shall keep Gulf Power reasonably informed as to the progress of its efforts to obtain the FPSC Approval.

9.4.2

If the FPSC Approval is not received by the Approval Deadline or if the FPSC issues an order denying FPUC’s request for the FPSC Approval (“FPSC Denial”) prior to the Approval Deadline, FPUC shall be entitled to provide notice to Gulf Power that it desires to immediately terminate this Agreement, provided that such notice must be provided within 10 Days after the first to occur of the Approval Deadline or the date of the FPSC Denial.  If FPUC does not provide such notice within such time period, then this Agreement shall continue in full force and effect for the remainder of the Term.  If FPUC provides such notice within such time period, then this Agreement shall immediately terminate and no Party shall have any further obligation or liability to the other Party under this Agreement.

9.5

Subsequent Action of the Florida Public Service Commission.  

9.5.1

After the Approval Deadline, if the FPSC issues an order with respect to this Agreement that prohibits FPUC from recovering from its Northwest Division

customers a material portion of the payments required to be made to Gulf Power under this Agreement, including payments resulting from Increased Costs (each such order being referred to as a “Disallowance Order”), then FPUC shall be entitled to provide notice to Gulf Power that it desires to terminate this Agreement, provided that such notice must be provided to Gulf Power within 60 Days after the issuance of the Disallowance Order.  If FPUC does not provide such notice within such time period, then FPUC shall be deemed to have waived its right to provide such notice with respect to the Disallowance Order giving rise to such right.  If FPUC provides such notice within such time period, then Gulf Power shall respond to FPUC within 60 Days after receiving such notice that Gulf Power either: (i) accepts such termination; or (ii) does not accept such termination.  

9.5.2

Notwithstanding the issuance of a Disallowance Order, this Agreement shall continue in full force and effect as originally executed on the Effective Date (including all payment provisions) for the next 365 Days of the Service Term after such Disallowance Order (“Continuation Period”).  If Gulf Power elects to accept termination in its notice under Section 9.5.1 with respect to a Disallowance Order, upon the expiration of the Continuation Period, this Agreement shall immediately terminate and neither Party shall have any further liability or obligation to the other hereunder (except for liabilities and obligations accruing prior to termination).  If Gulf Power elects to not accept termination in its notice under Section 9.5.1 with respect to a Disallowance Order, effective upon the expiration of the Continuation Period, this Agreement shall be deemed amended (but only until such time that the FPSC allows FPUC to recover the previously disallowed amount) such that with respect to capacity and energy provided under this

Agreement after the Continuation Period, FPUC will only be required to pay those amounts which such Disallowance Order allows FPUC to recover from its Northwest Division customers.

ARTICLE 10

INDEMNIFICATION; TITLE; COSTS AND EXPENSES

10.1

Indemnification.  The following provisions shall apply with respect to energy deemed delivered hereunder to FPUC:

10.1.1

Gulf Power shall defend, indemnify and save FPUC and its respective officers, directors, agents, employees and Affiliates harmless, on an After-Tax Basis, from and against any and all claims, liabilities, actions, demands, judgments, losses, costs, expenses (including reasonable attorney's fees) arising out of, resulting from, or in any way connected with the generation, transmission, or delivery of such energy and associated capacity prior to the Delivery Point(s) (whether or not the same is caused or arises out of joint, concurrent or contributory negligence of FPUC), except to the extent the same is caused by willful misconduct of an officer, director, subcontractor, agent or employee of FPUC.

10.1.2

FPUC shall defend, indemnify and save Gulf Power, its officers, directors, agents, employees and Affiliates harmless, on an After-Tax Basis, from and against any and all claims, liabilities, actions, demands, judgments, losses, costs, expenses (including reasonable attorney's fees) arising out of, resulting from, or in any way connected with the generation, transmission, or use of such energy and associated capacity at and after the Delivery Point(s) (whether or not the same is caused or arises out of joint, concurrent or contributory negligence of Gulf Power), except, in each case, to the

extent the same is caused by willful misconduct of an officer, director, subcontractor, agent or employee of Gulf Power (as applicable).

10.1.3  The rights, obligations and protections afforded by this Section 10.1 shall survive the termination, expiration or cancellation of this Agreement, and shall apply to the fullest extent permitted by law.  

10.1.4

A Party that becomes entitled to indemnification under this Agreement (“Indemnified Party”) shall promptly notify the Party required to indemnify such Indemnified Party (“Indemnifying Party”) of any claim or proceeding in respect of which it is to be indemnified.  Such notice shall be given as soon as reasonably practicable after the Indemnified Party becomes aware of such claim or proceeding.  Failure to give such notice shall not excuse an indemnification obligation except to the extent failure to provide notice adversely affects the Indemnifying Party’s interests.  The Indemnifying Party shall assume the defense thereof with counsel designated by the Indemnifying Party; provided, however, that if the defendants in any such action include both the Indemnified Party and the Indemnifying Party and the Indemnified Party reasonably concludes that there may be l egal defenses available to it that are different from or additional to, or inconsistent with, those available to the Indemnifying Party, the Indemnified Party shall have the right to select and be represented by separate counsel.  The Indemnified Party shall be responsible for the expenses associated with such separate counsel, unless a liability insurer will pay the expenses of such separate counsel.  If the Indemnifying Party fails to assume the defense of a claim, the indemnification of which is required under this Agreement, the Indemnified Party may, at the expense of the Indemnifying Party, contest, settle, or pay such claim; provided, however, that settlement

or full payment of any such claim may be made only with the Indemnifying Party’s consent or, absent such consent, written opinion of the Indemnified Party’s counsel that such claim is meritorious or warrants settlement.

10.2  Fees, Charges and Taxes.  Except as otherwise provided hereunder, all fees, charges and taxes associated with energy delivered hereunder at and after the Delivery Point(s) shall be the sole responsibility of FPUC.  Except as otherwise provided hereunder (e.g., those provisions that require FPUC to reimburse Gulf Power for certain fees, charges and taxes, such as Increased Costs), all fees, charges and taxes associated with such energy prior to the Delivery Point(s) shall be the sole responsibility of Gulf Power.    

10.3  Title.  Title to energy delivered hereunder shall pass from Gulf Power to FPUC at the Delivery Point(s), and FPUC shall be deemed to be in exclusive possession and control of such energy at and after such point(s).    

ARTICLE 11

FORCE MAJEURE

11.1

Force Majeure Event.

11.1.1

For the purposes of this Agreement, a “Force Majeure Event” as to a Party means any occurrence, nonoccurrence or set of circumstances, whether or not foreseeable, that is beyond the reasonable control of such Party and is not caused by such Party’s negligence or lack of due diligence, including any strike, stoppage in labor, failure of contractors or suppliers of materials or services, flood, ice, earthquake, storm or eruption; fire; explosion; invasion, riot, war, commotion or insurrection; sabotage, terrorism or vandalism; military or usurped power; or act of God or of a public enemy.  The term Force Majeure Event shall not include: (i) a change or circumstance in market

conditions that affects the value of this Agreement for either Party; (ii) difficulty or inability to make payments for any reason; (iii) FPUC’s inability to use or a lack of need for the capacity and energy purchased hereunder except to the extent such lack of need arises as a result of one or more Transmission Force Majeure Events; or (iv) FPUC’s inability, to any extent, to recover in its customer rates the amounts to be paid under this Agreement for any reason, including due to action or inaction of any Governmental Authority.

11.1.2

Subject to Sections 11.1.3, 11.2 and 11.3 below, either Party shall be excused from performance (other than payment obligations) and shall not be construed to be in breach or default in respect of any obligation hereunder for so long as the affected Party is rendered unable to perform such obligation due to a Force Majeure Event.

11.1.3

Subject to the limits set forth in Sections 11.1.3.1 and 11.1.3.2, during the suspension of performance due to or resulting from a Force Majeure Event, FPUC shall not be relieved from the obligation to make and be responsible for Monthly Capacity Payments and Monthly Energy Payments.

11.1.3.1

In the event that Gulf Power suspends performance under this Agreement for a period greater than 90 consecutive Days due to a Force Majeure Event directly affecting Gulf Power’s generation resources prior to the Delivery Point(s), the Monthly Capacity Payment(s) applicable to capacity provided after such 90 Day period shall be reduced on a pro rata basis to reflect the amount of energy Gulf Power does not provide after such 90 Day period as a result of such event.

11.1.3.2

In the event that a Transmission Force Majeure Event occurs for a period greater than 90 consecutive Days, the Monthly Capacity Payment(s)

applicable to capacity provided after such 90 Day period shall be reduced on a pro rata basis to reflect the amount of energy that FPUC is unable to receive after such 90 Day period as a result of such event.          

11.2

Notice and Remedy of Force Majeure Events.  Following the occurrence of a Force Majeure Event, the affected Party shall:

11.2.1

give the other Party notice thereof, followed by written notice if the first notice is not written, as promptly as practicable after such Party becomes aware of such Force Majeure Event, describing the particulars of such Force Majeure Event;

11.2.2

use its reasonable best efforts consistent with Prudent Utility Practice to remedy its inability to perform as soon as practicable; provided, however, that this Section shall not require the settlement of any strike, walkout, lockout or other labor dispute on terms which in the sole judgment of the Party involved in the dispute, are contrary to its interest; provided further, that the settlement of strikes, lockouts or other labor disputes shall be entirely within the discretion of the Party having the difficulty; and

11.2.3

provide the other Party with written notice when it is able to resume performance of its obligations under this Agreement.

11.3

Suspension of Performance.  The suspension of performance due to a Force Majeure Event shall be of no greater scope and of no longer duration than is required by such Force Majeure Event.  No Force Majeure Event shall extend this Agreement beyond its stated Term.

ARTICLE 12

EVENTS OF DEFAULT AND TERMINATION

12.1

Events of Default.  “Event of Default” shall mean the occurrence of any of the following events with respect to a Party (the “Defaulting Party,” and the Party not in default being a “Non-Defaulting Party”):

12.1.1 the failure by the Defaulting Party to make, when due, payment of any amount required under this Agreement if such failure is not remedied within 5 Banking Days after written notice of such failure is given to the Defaulting Party by the Non-Defaulting Party;

12.1.2 any representation or warranty of the Defaulting Party pursuant to this Agreement shall prove to have been false or misleading in any material respect when made or deemed made and have been known by the Defaulting Party to have been so at the time made or deemed made unless (a) the fact, circumstances or condition that is the subject of such representation or warranty is made true within 30 Days after notice thereof has been given to the Defaulting Party and (b) such cure removes any adverse effect on the Non-Defaulting Party of such fact, circumstance or condition being otherwise than as first represented;

12.1.3 the Defaulting Party or its Guarantor:

(a)

makes a general assignment or arrangement for the benefit of its creditors;

(b)

(i) files a petition or otherwise commences, authorizes, or acquiesces in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or (ii) has such petition filed or

proceeding commenced against it and, in the case of a petition filed or proceeding commenced against it, such petition or proceeding results in a judgment of insolvency or bankruptcy or the entry of any order for relief or the making of an order for the winding-up or liquidation of such entity, or is not dismissed, discharged, stayed or restrained within 5 Banking Days of the filing or commencement thereof;

(c)

otherwise becomes bankrupt or insolvent;

(d)

fails or is unable or admits in writing its inability generally to pay its debts as they become due;

(e)

is dissolved (other than pursuant to a consolidation, acquisition, amalgamation or merger);

(f)

has a resolution passed for its winding-up, official management or liquidation (other than pursuant to a consolidation, acquisition, amalgamation or merger);

(g)

seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for all or substantially all of its assets;

(h)

has a secured party take possession of all or substantially all of its assets, or has a distress, execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all of its assets and subject secured party maintains possession, or any such process is not dismissed, discharged, stayed or restrained, in each case within 30 Days thereafter;

(i)

causes or is subject to any event with respect to it which, under the applicable laws of any jurisdiction, has an analogous effect to any of the events specified in Section 12.1.3 clauses (a) through (h) (inclusive);

(j)

takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts; or

(k)

merges with any other party and the surviving entity does not assume the Defaulting Party’s or its Guarantor’s obligations with respect to this Agreement;

12.1.4 the material failure by the Defaulting Party to perform or observe any material obligation or covenant set forth in this Agreement (other than obligations which are otherwise specifically covered in this Section 12.1 as a separate Event of Default), and such failure is not cured within 60 Days after written notice of such default is given to the Defaulting Party;

12.1.5 the Defaulting Party or its Guarantor defaults on obligations under one or more agreements or instruments in respect of debt and such default continues after the applicable grace period, if any, specified in such agreement or instrument if the principal amount of such obligations equal or exceed ten million dollars ($10,000,000.00), and such default results in such debt becoming, or becoming capable at such time of being declared, due and payable prior to its stated maturity, whether or not such debt is in fact declared due and payable;

12.1.6

the failure by a Party to maintain the Eligible Collateral as required under Article 13, unless such failure is cured within 3 Banking Days after such Party receives notice of such failure.

12.2

Notification of Default.  In the event a Party becomes aware of any event or circumstance that constitutes an Event of Default, such Party shall promptly notify the other Party.

12.3

Event of Default by Gulf Power.

12.3.1  Upon and after the occurrence of an Event of Default by Gulf Power, so long as such Event of Default is continuing, FPUC shall be entitled to suspend the performance of its obligations to Gulf Power under this Agreement, except for the obligations to pay for energy and capacity provided by Gulf Power prior to termination of this Agreement.  In addition to such suspension, if an Event of Default by Gulf Power has occurred and is continuing, FPUC shall have the right by notice to Gulf Power to take one or more of the following actions in its sole discretion: (i) terminate this Agreement; (ii) pursue an action for equitable relief by recourse to a court of competent jurisdiction, but only to the extent necessary to effect a cure of such Event of Default; or (iii) if the Event of Default is for the failure to pay an amount of money pursuant to this Agreement, pursue an action for damag es equal to (but no greater than) the amount of money not paid pursuant to the procedure set forth in Article 16.  Provided, however, notwithstanding anything to the contrary in this Agreement, FPUC shall not be entitled to take or maintain more than one of the actions in (i) through (iii) of the foregoing sentence at the same time with respect to the same Event of Default, and in no event shall FPUC be entitled to receive both FPUC Liquidated Damages and a remedy under (ii) or (iii) of the foregoing sentence as a result of the same Event of Default.  

12.3.2  If FPUC elects option (i) in a notice under Section 12.3.1, FPUC shall designate a Banking Day in such notice that is no more than 120 Days from the date of

such notice (such designated date being referred to as the “FPUC Termination Date”).  On the FPUC Termination Date, (i) Gulf Power shall pay to FPUC the FPUC Liquidated Damages; and (ii) this Agreement shall terminate and no Party shall have any further liability or obligation to the other Party under this Agreement, except for any obligations and liabilities occurring prior to termination and Gulf Power’s obligation to pay the amounts under this Section 12.3.  

12.3.3

As used herein, “FPUC Liquidated Damages” means the aggregate sum of what the Monthly Capacity Payments would have been under this Agreement (assuming no Event of Default had occurred and no termination or modification of this Agreement), as reasonably determined by FPUC, for the lesser of: (i) (A) if the FPUC Termination Date occurs after the commencement of the Service Term, the 24 Months following the Month in which the FPUC Termination Date occurs, or (B) if the FPUC Termination Date occurs prior to the Service Term, the first 24 Months of the Service Term; or (ii) the Months remaining in the Service Term.

12.4

Event of Default by FPUC.

12.4.1  Upon and after the occurrence of an Event of Default by FPUC, so long as such Event of Default is continuing, Gulf Power shall be entitled to suspend the performance of its obligations to FPUC under this Agreement; provided, however, that Gulf Power shall provide FPUC with at least 5 Days prior written notice before suspending the provision of capacity and energy due to an Event of Default, which notice may be provided with (and such 5 Day notice period may run concurrent with the notice period in) any notice provided under Sections 12.1.1, 12.1.2, 12.1.4 or 12.1.6.  In addition to such suspension, if an Event of Default by FPUC has occurred and is continuing, Gulf

Power shall have the right by notice to FPUC to take one or more of the following actions in its sole discretion: (i) terminate this Agreement; (ii) pursue an action for equitable relief by recourse to a court of competent jurisdiction, but only to the extent necessary to effect a cure of such Event of Default; or (iii) if the Event of Default is for the failure to pay an amount of money pursuant to this Agreement, pursue an action for damages equal to (but no greater than) the amount of money not paid pursuant to the procedure set forth in Article 16.  Provided, however, notwithstanding anything to the contrary in this Agreement, Gulf Power shall not be entitled to take or maintain more than one of the actions in (i) through (iii) of the foregoing sentence at the same time with respect to the same Event of Default, and in no event shall Gulf Power be entitled to receive both Gulf Liqui dated Damages and a remedy under (ii) or (iii) of the foregoing sentence as a result of the same Event of Default.  

12.4.2  If Gulf Power elects option (i) in a notice under Section 12.4.1, Gulf Power shall designate a Banking Day in such notice that is no more than 120 Days from the date of such notice (such designated date being referred to as the “Gulf Termination Date”). On the Gulf Termination Date, (i) FPUC shall pay to Gulf Power the Gulf Liquidated Damages; and (ii) this Agreement shall terminate and no Party shall have any further liability or obligation to the other Party under this Agreement, except for any obligations and liabilities accruing prior to termination and FPUC’s obligation to pay the amounts under this Section 12.4.

12.4.3  As used herein, “Gulf Liquidated Damages” means the aggregate sum of what the Monthly Capacity Payments would have been under this Agreement (assuming no Event of Default had occurred and no termination or modification of this Agreement),

as reasonably determined by Gulf Power, for the lesser of: (i) (A) if the Gulf Termination Date occurs after the commencement of the Service Term, the 24 Months following the Month in which the Gulf Termination Date occurs, or (B) if the Gulf Termination Date occurs prior to the Service Term, the first 24 Months of the Service Term; or (ii) the Months remaining in the Service Term.  

12.5

Exclusive Remedy.  The exercise by a Party of its rights under Section 12.3 or 12.4 (as applicable) shall be the sole and exclusive remedy (whether arising in contract, tort or otherwise) of such Party for an Event of Default by or attributable to the Defaulting Party.  The Parties acknowledge and agree that in the event of an Event of Default, all or a portion of the amount of damages arising therefrom are not susceptible to an accurate determination.  The Parties further acknowledge and agree that the liquidated damages set forth above are not intended as a penalty and represent a fair and reasonable approximation of all or a portion of the damages a Non-Defaulting Party may incur in each particular case.

ARTICLE 13

CREDITWORTHINESS AND SECURITY

13.1

FPUC’s Provision of Eligible Collateral.  If and for so long as FPUC does not have an Acceptable Rating and FPUC has or will have remaining payment obligations under this Agreement, then FPUC shall provide to and maintain in favor of Gulf Power Eligible Collateral that unconditionally secures all of FPUC’s obligations to Gulf Power under this Agreement, in an amount not less than the Required FPUC Collateral Amount.  Such Eligible Collateral shall be provided to Gulf Power within 10 Days after FPUC’s receipt of notice from Gulf Power (or its agent) of the requirement to provide Eligible Collateral pursuant to the provisions of this Section.  So long as no Event of Default by or attributable to FPUC shall have occurred and be

continuing, Gulf Power shall cooperate with FPUC, at FPUC’s request and expense, to release and return to FPUC Eligible Collateral theretofore provided by FPUC to and then held by Gulf Power if and to the extent FPUC contemporaneously provides to Gulf Power replacement or substitute Eligible Collateral in equal or greater amount that satisfies the requirements of this Section.  If, at any time, the Required FPUC Collateral Amount shall be more than the amount of the Eligible Collateral provided by FPUC to and then held by Gulf Power, FPUC shall, within 10 Days of Gulf Power’s request, have additional Eligible Collateral in the amount of such difference provided to Gulf Power unless FPUC is no longer required to maintain such Eligible Collateral under the terms hereof.  So long as no Event of Default by or attributable to FPUC shall have occurred and be continuing hereunder, if, on the first Banking Day of any Year, the Required FPUC Collateral Amount shall be less than the amount of the Eligible Collateral theretofore provided by FPUC to and then held by Gulf Power, Gulf Power shall cooperate with FPUC, at FPUC’s request and expense, to have such Eligible Collateral then held by Gulf Power reduced by the amount of such difference, subject to FPUC’s obligation to thereafter provide Eligible Collateral to Gulf Power in order to comply with the provisions of this Section.  In addition, at such time that FPUC has an Acceptable Rating and so long as no Event of Default by or attributable to FPUC shall have occurred and be continuing hereunder, FPUC may request and Gulf Power shall cooperate with FPUC, at FPUC’s expense, to have the Eligible Collateral theretofore provided by FPUC and then held by Gulf Power released and returned to FPUC, subject to FPUC’s obligation to thereafter provide Eligible Collateral to Gulf Power in order to comply with the provisions of this Sectio n.   Notwithstanding anything to the contrary contained or implied above, the Required FPUC Collateral Amount shall be and remain reduced by the

dollar amount of any payment received by Gulf Power in connection with its realizing upon Eligible Collateral theretofore provided by FPUC to Gulf Power pursuant to this Section.

13.2

Gulf Power’s Provision of Eligible Collateral.  If and for so long as Gulf Power does not have an Acceptable Rating and Gulf Power has or will have remaining payment obligations under this Agreement, then Gulf Power shall provide to and maintain in favor of FPUC Eligible Collateral that unconditionally secures all of Gulf Power’s obligations to FPUC under this Agreement, in an amount not less than the Required Gulf Collateral Amount.  Such Eligible Collateral shall be provided to FPUC within 10 Days after Gulf Power’s receipt of notice from FPUC of the requirement to provide Eligible Collateral pursuant to the provisions of this Section.  So long as no Event of Default by or attributable to Gulf Power shall have occurred and be continuing, FPUC shall cooperate with Gulf Power, at Gulf Power’s request and expense, to release and return to Gulf Power Eligible Collateral theretofore provided by Gulf Power to and then held by FPUC if and to the extent Gulf Power contemporaneously provides to FPUC replacement or substitute Eligible Collateral in equal or greater amount that satisfies the requirements of this Section.  If, at any time, the Required Gulf Collateral Amount shall be more than the amount of the Eligible Collateral provided by Gulf Power to and then held by FPUC, Gulf Power shall, within 10 Days of FPUC’s request, have additional Eligible Collateral in the amount of such difference provided to FPUC unless Gulf Power is no longer required to maintain such Eligible Collateral under the terms hereof.  So long as no Event of Default by or attributable to Gulf Power shall have occurred and be continuing hereunder, if, on the first Banking Day of any Year, the Required Gulf Collateral Amount shall be less than the amount of the Eligible Collateral theretofore provided by Gulf Power to and then held by FPUC, FPUC shall cooperate with Gulf Power, at Gulf Power’s request and expense, to have such Eligible Collateral then held

by FPUC reduced by the amount of such difference, subject to Gulf Power’s obligation to thereafter provide Eligible Collateral to FPUC in order to comply with the provisions of this Section.  In addition, at such time that Gulf Power has an Acceptable Rating and so long as no Event of Default by or attributable to Gulf Power shall have occurred and be continuing hereunder, Gulf Power may request and FPUC shall cooperate with Gulf Power, at Gulf Power’s expense, to have the Eligible Collateral theretofore provided by Gulf Power and then held by FPUC released and returned to Gulf Power, subject to Gulf Power’s obligation to thereafter provide Eligible Collateral to FPUC in order to comply with the provisions of this Section.  Notwithstanding anything to the contrary contained or implied above, the Required Gulf Collateral Amount shall be and remain reduced by the dollar amount of any pay ment received by FPUC in connection with its realizing upon Eligible Collateral theretofore provided by Gulf Power to FPUC pursuant to this Section.  

13.3

Compliance Certificate.  A Party who does not have any of: (i) an issuer credit rating or senior unsecured rating by S&P; or (ii) an issuer rating or senior unsecured rating by Moody’s shall furnish or cause to be furnished to the other Party quarterly within 45 Days of the end of each quarter a completed certificate of the chief financial officer of such Party, substantially in the form of Appendix E hereto.

ARTICLE 14

REPRESENTATIONS AND WARRANTIES

14.1

Execution.  Each Party represents and warrants to the other Party as of the Effective Date that: (i) it has all the necessary corporate and legal power and authority and has been duly authorized by all necessary corporate action to enable it to lawfully execute, deliver and perform under this Agreement; and (ii) it is a valid legal entity duly organized and validly

existing in good standing under the laws of the state of its formation and is, to the extent required, qualified to do business in the state where it is organized.  

14.2

Binding Obligations.  Each Party represents and warrants to the other Party that as of the Effective Date this Agreement is the valid and binding obligation of such Party, enforceable against such Party in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar laws affecting enforcement generally, and by equitable principles regardless of whether such principles are considered in a proceeding at law or in equity.

14.3

Execution and Consummation.  Each Party represents and warrants to the other Party that as of the Effective Date the execution and delivery of this Agreement, the consummation of the transactions contemplated hereby and the fulfillment of and compliance with the provisions of this Agreement do not and will not conflict with any of the terms, conditions or provisions of its organizational documents or any law applicable to it or result in a breach or default under any evidence of its indebtedness or any other agreement or instrument to which it is a party or by which it or any of its property is bound which has a reasonable likelihood of materially and adversely affecting the consummation of the transactions contemplated hereby or the performance by the Party of any of its obligations under this Agreement.

14.4

Actions and Proceedings.  Each Party represents and warrants to the other that as of the Effective Date there is no pending or, to the knowledge of such Party, threatened action or proceeding affecting such Party before any Governmental Authority that has a reasonable likelihood of materially adversely affecting or reasonably threatening the ability of such Party to perform its obligations under this Agreement or the validity or enforceability of this Agreement

against it and that there are no bankruptcy proceedings pending or being contemplated by it or, to its knowledge, threatened against it.

14.5

Absence of Certain Events.

Each Party represents and warrants to the other Party that as of the Effective Date no Event of Default attributable to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Agreement.

ARTICLE 15

CONFIDENTIALITY

15.1

Confidential Information.  “Confidential Information” shall mean business or technical information of a Party rightfully in the possession of such Party, which information derives independent actual or potential commercial value from not being generally known or readily ascertainable through independent development or reverse engineering by Persons who can obtain economic value from its disclosure and use, and which information is the subject of efforts that are reasonable under the circumstances to maintain its secrecy.  Confidential Information consists of information designated as confidential and furnished by a Party to another Party in discussions leading up to execution of this Agreement (including in Gulf Power’s proposals to FPUC) and during the Term of this Agreement, and the detailed terms and pricing information contained in this Agreement.  

15.2

Disclosure of Confidential Information.

15.2.1

Each Party agrees that during the Term of this Agreement and for a period of 5 Years from the date of termination of this Agreement it will not, without the written consent of the other Party or as otherwise provided herein, disclose Confidential Information of another Party to any other party; provided, however, each Party shall be

entitled to disclose Confidential Information to its (or its Affiliates’) agents, employees, officers, directors, representatives, contractors, advisors, lenders, accountants, rating agencies, underwriters, consultants and advisors who need to know such information in connection with the performance of their duties or services for such Party or Affiliates or in connection with the analysis, issuance or rating of any debt or equity securities or financial activities of such Party or Affiliates; provided, further, that such parties shall be bound by an obligation to maintain the confidentiality of such Confidential Information and such Party shall be responsible for any use or disclosure by such parties of any Confidential Information inconsistent with this Article 15.

15.2.2

To the extent Gulf Power is required to provide Confidential Information in this Agreement to FERC, Gulf Power shall seek confidential treatment of such Confidential Information from FERC, and FPUC will provide reasonable cooperation in connection with such request.  Notwithstanding the foregoing, the Parties acknowledge that certain Confidential Information may need to be disclosed in filings with FERC which may become publicly available.  In the event this Agreement becomes publicly available, Gulf Power will promptly notify FPUC once Gulf Power learns of this fact; provided, however, that regardless of whether such notification is provided, the provisions of this Article 15 shall no longer apply to this Agreement if this Agreement becomes publicly available as a result of filings with FERC or otherwise.

15.2.3

Each Party may file this Agreement and Confidential Information with the Securities and Exchange Commission (“SEC”) as may be necessary under Laws in connection with such Party’s application to the SEC for such orders and approvals as may be required for financing and/or the issuance and sale of interests in or debt issued or to

be issued by such Party and/or its Affiliates.  Such Party shall request confidential treatment of this Agreement and Confidential Information in connection with such filing; however, the Parties acknowledge that such request may be denied in whole or in part, and accordingly, that confidential treatment may not be afforded by the SEC to such information.  In addition, each Party may disclose Confidential Information as required by the SEC pursuant to the Securities and Exchange Act of 1934, as amended, and any rule or regulation promulgated thereunder.  In the event any Confidential Information will need to be disclosed in connection with a filing under this Section 15.2.3, the Parties shall consult and cooperate with each other prior to such disclosure, including, without limitation, in determining the extent to which confidential treatment will be sought for such terms, con ditions and provisions.

15.2.4

The Parties agree to seek confidential treatment of this Agreement and other Confidential Information from the FPSC to the maximum extent possible pursuant to Chapter 366.093, Florida Statutes, and Rule 25-22.006 of the Florida Administrative Code.  In the event any Confidential Information will need to be disclosed in connection with any application for the FPSC approval of this Agreement or the rates to be charged hereunder, FPUC shall consult and cooperate with Gulf Power prior to such disclosure, including, without limitation, in determining the extent to which confidential treatment will be sought for such terms, conditions and provisions.

15.2.5

Nothing in this Section 15.2 shall prohibit or otherwise limit the use or disclosure of Confidential Information if such Confidential Information: (a) was previously known to the disclosing or using Party unrelated to this Agreement without an obligation of confidentiality; (b) was developed by or for the disclosing or using Party

unrelated to this Agreement using nonconfidential information; (c) was acquired by the disclosing or using Party from a third party which is not, to the disclosing or using Party’s knowledge, under an obligation of confidence with respect to such information; (d) is or becomes publicly available other than through a manner inconsistent with this Section 15.2; or (e) is provided or made available for inspection by any Party under public records or public disclosure laws but only to the extent required to be so provided or made available.

15.2.6

Notwithstanding anything in this Article 15 to the contrary, if a Party is required by applicable Law or in the course of administrative or judicial proceedings or investigations, to disclose to third parties, Confidential Information of the other Party or this Agreement, such required Party may make disclosure of such information; provided, however, that all reasonable steps are taken by such Party to assure continued confidential treatment by the relevant administrative, regulatory or judicial agencies or other recipient and provided further that as soon as such Party learns of the disclosure request or requirement or otherwise intends to disclose any such Confidential Information pursuant hereto and prior to making disclosure, such Party, to the extent permitted by law, notifies the other Party of the requirement, request or intention and the terms thereof and such other Party may challenge the d isclosure requirement, request or intention or seek a protective order or other appropriate remedy.  The required Party, at the expense of the Party whose Confidential Information would be disclosed, shall attempt to minimize the disclosure of such Confidential Information consistent with applicable law and attempt to obtain proprietary or confidential treatment of such Confidential Information by the Person to whom such Confidential Information will be disclosed (and if practicable,

reasonably prior to any such disclosure).  If, in the absence of a protective order or other appropriate remedy, the required Party is nonetheless, in the written opinion of counsel, legally compelled to disclose such Confidential Information or otherwise may become subject to contempt or other censure or penalty, the required Party may, in such instance but not otherwise, without liability hereunder, disclose that portion of such Confidential Information which and to whom such counsel advises the required Party is legally required to be disclosed (but none other).  

15.3

Remedies.  A breach of the confidentiality obligations of Section 15.2 by any Person with whom the receiving Party has shared Confidential Information of the disclosing Party shall be deemed a breach of this Article by the receiving Party.  The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation; provided that all monetary damages shall be limited to actual direct damages and a breach of the confidentiality obligations of Section 15.2, notwithstanding anything to the contrary in this Agreement, shall not give rise to a right to suspend or terminate this Agreement or result in an Event of Default hereunder.

ARTICLE 16

DISPUTE RESOLUTION

16.1

Dispute Resolution Generally.

16.1.1

Except as allowed otherwise in Section 12.3.1(ii) or 12.4.1(ii), in the event any dispute arises out of or in connection with this Agreement or its performance (including the existence, validity and interpretation of this Agreement), a Party (the “Disputing Party”) shall provide the other Party (the “Responding Party”) with a written notice of the particular dispute for each issue in dispute, a proposed means for resolving

each such issue, and support for such position (the “Notice of Dispute”).  Within 30 Days after receiving the Notice of Dispute, the Responding Party shall provide the Disputing Party with a written notice of each additional issue (if any) with respect to the dispute raised by the Notice of Dispute, a proposed means for resolving every issue in dispute, and support for such position (the “Dispute Response”).

16.1.2

Within 15 Days after the submission of the Dispute Response, the administrative representatives of each Party shall meet to discuss the matter and attempt in good faith to reach a negotiated resolution of the dispute.  If the administrative representatives do not resolve the dispute by unanimous agreement within 30 Days after receipt of the Dispute Response, or such other time period as the Parties may agree in writing to allow for discussions (the “Negotiation Period”), the dispute shall be submitted to a senior executive of each of the Parties for resolution.  If the dispute is not resolved after 60 Days from the submission to such senior executives, then either Party may provide written notice to the other Party declaring an impasse (the “Impasse Notice”) and initiating binding arbitration in accordance with the further provisions of this Article 16.

16.2

Initiation of Arbitration; Selection of Arbitrators.

16.2.1

Arbitration will be deemed to be initiated when an Impasse Notice is given by the delivering Party to the receiving Party in accordance with the notice provisions of Section 17.11.  The Party initiating arbitration shall nominate 1 arbitrator at the same time it initiates arbitration.  The other Party shall nominate 1 arbitrator within 20 Days of receiving the Impasse Notice.  Each of the 2 arbitrators appointed by the Parties (the “Party-Appointed Arbitrators”) shall not be and shall not have been previously an employee or agent of or consultant or counsel to either Party and will not have a direct or

indirect interest in either Party or the subject matter of the arbitration.   The Party-Appointed Arbitrators shall appoint a third, neutral arbitrator (the “Third Arbitrator”) within 10 Days after the last Party-Appointed Arbitrator is appointed.  The Third Arbitrator shall be competent and experienced in matters involving the electric energy business in the United States, with at least 5 years of electric industry experience, and shall be impartial and independent of either Party and the Party-Appointed Arbitrators.

16.2.2

If the Party-Appointed Arbitrators are unable to agree on the Third Arbitrator within 60 Days from initiation of arbitration, then the Third Arbitrator shall be selected by the American Arbitration Association (the “AAA”) with due regard given to the selection criteria above and input from the Parties and the Party-Appointed Arbitrators.  The Parties shall undertake to request the AAA to complete selection of the Third Arbitrator no later than 90 Days from initiation of arbitration.  Costs charged by the AAA for this service shall be borne by the Parties in accordance with Section 16.5.

16.2.3

In the event the AAA should fail to select the Third Arbitrator within 90 Days from initiation of arbitration, then either Party may petition a court of competent jurisdiction in Florida to select the Third Arbitrator.  Due regard shall be given to the selection criteria above and input from the Parties and the Party-Appointed Arbitrators.

16.2.4

If prior to the conclusion of the arbitration a Party-Appointed Arbitrator or the Third Arbitrator becomes incapacitated or otherwise unable to serve, then a replacement arbitrator shall be appointed in the manner described above and applicable to the original arbitrator being replaced.

16.3

Discovery, Hearing.  Discovery and other pre-hearing procedures shall be conducted as agreed to by the Parties, or if they cannot agree, as determined by a majority of the

Party-Appointed Arbitrators and the Third Arbitrator; provided, however, all pre-hearing discovery shall be completed within 180 Days following selection of the Third Arbitrator.  Within 15 Days after completion of such pre-hearing discovery, the Parties shall submit to each other by overnight delivery, the Party-Appointed Arbitrators and the Third Arbitrator a separate precise statement for each issue in dispute, that party’s proposed means of resolving each issue in dispute, and the factual or legal support for such proposal (the “Proposed Resolutions”).  No later than 30 Days after all pre-hearing discovery has been completed, a hearing shall be conducted at which the Parties shall each present such evidence and witnesses as they may choose.  Arbitration shall be conducted in accordance with the Commercial Arbitration Rules of the AAA, as amended and supplemented, except where specifically modified by this Agreement.

16.4

Decision.  The Party-Appointed Arbitrators and the Third Arbitrator shall consider the terms and conditions of this Agreement and all relevant evidence and testimony, and shall render their decision within 90 Days following conclusion of the hearing; provided, however, the Party-Appointed Arbitrators and the Third Arbitrator are expressly and specifically limited to selecting one (1) of the Proposed Resolutions for each issue in dispute provided by the Parties; provided, further, the Party-Appointed Arbitrators and the Third Arbitrator shall not have the authority to effect any other resolution of the issues in dispute.  The decision rendered by a majority of the Party-Appointed Arbitrators and the Third Arbitrator, made in writing, shall be final and binding upon the Parties.  Any such decision may be filed in a court of competent jurisdiction and may be enforced by the Parties as a final judgment in such court.  The Party-Appointed Arbitrators and the Third Arbitrator shall have no authority to award special, exemplary, or consequential damages.

16.5

Expenses of Arbitration.  Each Party shall bear the compensation and expenses of its respective Party-Appointed Arbitrator, own counsel, witnesses, consultants and employees.  All other expenses of arbitration (the “Arbitration Expenses”) shall be borne by the Parties equally.  Notwithstanding the foregoing provisions of this Section 16.5, any costs incurred by the Parties in seeking judicial enforcement of any decision rendered in writing by a majority of the Party-Appointed Arbitrators and the Third Arbitrator, shall be chargeable to and borne exclusively by the Party against whom such court order is obtained.

16.6

Confidentiality.  All disputes resolved pursuant to this Article 16 shall be subject to the confidentiality provisions set forth in Article 15.

ARTICLE 17

MISCELLANEOUS PROVISIONS

17.1

Assignment.

17.1.1

Neither Party may directly (by way of merger, consolidation or otherwise) assign this Agreement or its rights and obligations hereunder in whole, in part or collaterally without the written consent of the other Party (which consent shall not be unreasonably withheld, conditioned or delayed); provided that, notwithstanding the foregoing, either Party may assign this Agreement and its rights and obligations hereunder directly (by way of merger, consolidation or otherwise) without the consent of the other Party to any Person or entity who: (i) has the legal power and authority to perform and satisfy the obligations of such assigning Party under this Agreement; and (ii) has an Acceptable Rating or provides the credit support required by Article 13 of this Agreement.  The assigning Party will notify the other Party in writing prior to any assignment with respect to which consent is not required here under.  No assignment by a

Party of this Agreement or its rights or obligations hereunder shall relieve the assigning Party of liability for its obligations under this Agreement without the written release of the other Party.  Such release shall not be withheld if the Assignment Conditions (defined below) are satisfied.  

17.1.2

The non-assigning Party’s obligation to recognize or perform for any Person or entity claiming rights in this Agreement by outright assignment, by way of merger or consolidation or as the result of the realization or foreclosure upon a collateral assignment permitted by this Agreement (an “Assignee”), shall be subject to such Assignee: (i) establishing that it (a) has the legal power and authority to perform and satisfy the obligations of its assigning Party under this Agreement and (b) has an Acceptable Rating or has provided the credit support required by Article 13 of this Agreement; (ii) having cured all existing Events of Default attributable to the assigning Party under this Agreement; and (iii) having executed and delivered to the non-assigning Party and being in compliance with an assignment and assumption agreement whereby the Assignee assumes and agrees to satisfy all condit ions and pay and perform all obligations in favor of the non-assigning Party then existing and/or thereafter arising under this Agreement (the “Assignment Conditions”).

17.1.3

Notwithstanding anything to the contrary contained or implied in this Section 17.1, either Party may (without the other Party’s consent) assign, transfer, mortgage and/or pledge this Agreement and any and all of its rights hereunder as security for any obligation secured in whole or part by any indenture, mortgage, security interest or other lien on any or all of its generating facilities.

17.2

Agents of the Parties.  

17.2.1

Gulf Power hereby designates SCS as its agent for purposes of the implementation and administration of this Agreement.  Gulf Power may designate a new agent from time to time under this Agreement by giving FPUC written notice in which event SCS’s role, as agent, shall cease and the newly-designated agent shall be substituted for the sole purpose of serving and acting as agent for Gulf Power hereunder.

17.2.2

Wherever this Agreement requires a Party to provide information, schedules, notice or the like to, or to take direction from, another Party or its agent, the Party required to take such action shall provide such information, schedules, notice or the like to, or take direction from, whichever of such other Party, its agent or both that such other Party may direct from time to time.  Each Party shall be accountable for the acts or omissions of its agents.  In the event a Party’s agent does not perform in accordance with this Agreement, such Party shall be in breach of this Agreement.   

17.3

No Partnership.  The Parties do not intend for this Agreement to, and this Agreement shall not, create any joint venture, partnership, association taxable as a corporation, or other entity for the conduct of any business for profit.

17.4

Successors and Assigns.  This Agreement shall inure to the benefit of and be binding upon any respective successors and assigns of the Parties.

17.5

No Third Party Benefit.  Nothing in this Agreement shall be construed to create any duty, obligation or liability of Gulf Power or FPUC to any Person not a Party to this Agreement.

17.6

No Consequential Damages.  NOTWITHSTANDING ANY OTHER PROVISION OF THIS AGREEMENT, BUT SUBJECT TO ANY OBLIGATION FOR A

PARTY TO PAY LIQUIDATED DAMAGES UNDER SECTION 12.3.2 OR 12.4.2, THE SOLE AND EXCLUSIVE REMEDY FOR ANY LIABILITY UNDER THIS AGREEMENT SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES.  SUBJECT TO ANY OBLIGATION FOR A PARTY TO PAY LIQUIDATED DAMAGES UNDER SECTION 12.3.2 OR 12.4.2, NEITHER PARTY SHALL BE LIABLE TO THE OTHER PARTY FOR ANY SPECIAL, INDIRECT, INCIDENTAL, CONSEQUENTIAL, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES UNDER, ARISING OUT OF, DUE TO OR IN CONNECTION WITH ITS PERFORMANCE OR NONPERFORMANCE OF THIS AGREEMENT OR ANY OF ITS OBLIGATIONS HEREIN, WHETHER BASED ON CONTRACT, TORT (INCLUDING NEGLIGENCE), STRICT LIABILITY, WARRANTY OR OTHERWISE.  TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, THAT OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT, AND THAT THE LIQUIDATED DA MAGES CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.    

17.7

No Affiliate Liability.  NOTWITHSTANDING ANY OTHER PROVISION OF THIS AGREEMENT, NO AFFILIATE OF ANY PARTY (INCLUDING ANY AFFILIATE OF EITHER PARTY ACTING AS SUCH PARTY’S AGENT WHERE SUCH PARTY’S AGENT IS GIVEN CERTAIN AUTHORITIES HEREUNDER) SHALL HAVE ANY LIABILITY WHATSOEVER FOR SUCH PARTY’S PERFORMANCE, NONPERFORMANCE OR DELAY IN PERFORMANCE UNDER THIS AGREEMENT UNLESS SUCH AFFILIATE HAS BEEN ASSIGNED THIS AGREEMENT IN ACCORDANCE WITH SECTION 17.1.

17.8

Disclaimer of Warranty.  EXCEPT AS EXPRESSLY PROVIDED OTHERWISE IN THIS AGREEMENT, THERE ARE NO WARRANTIES UNDER THIS AGREEMENT, AND EACH PARTY HEREBY DISCLAIMS ANY AND ALL EXPRESS, IMPLIED OR STATUTORY WARRANTIES RELATING TO THE SUBJECT MATTER OF THIS AGREEMENT, INCLUDING ANY AND ALL WARRANTIES AS TO MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, AVAILABILITY, ACCURACY, QUALITY, QUANTITY OR OTHERWISE.

17.9

Time of Essence; No Waiver.

17.9.1

Time is of the essence of this Agreement.

17.9.2

No Party’s failure to enforce, at any time, any provision of this Agreement or to require at any time performance by another Party of any provision of this Agreement, shall in any way be construed as a waiver of any such provision, nor prevent such Party from enforcing each and every other provision of this Agreement at such time or at any time thereafter, nor in any way affect the validity of this Agreement or any part hereof, or the right of either Party thereafter to enforce each and every such provision.  No waiver of all or any part of this Agreement shall be valid unless it is reduced to a writing, expressly stating that the Parties agree to such waiver, and is duly executed by the Parties.

17.10

Amendments.  Except as otherwise provided in this Agreement, this Agreement may be amended only by a written instrument, duly executed by each of the Parties, which has received all acceptances or approvals of Governmental Authorities with competent jurisdiction necessary for the effectiveness thereof.

17.11

Notice.  Any notice, request, consent or other communication permitted or required by this Agreement shall be in writing and shall be deemed given on the Day hand-

delivered to the officer of the receiving Party identified below, or the Day received by the receiving Party below if other means are selected by the Party providing notice, which Day of receipt must be established by appropriate evidence that can be authenticated by the receiving Party (e.g., certified mail, prepaid, return receipt requested, with the United States Postal Service).

If given to Gulf Power, it shall be addressed to:

Vice President, Southern Wholesale Energy

Southern Company Services, Inc.

600 18^th Street North

Birmingham, AL 35203

Facsimile:  (205) 257-2163

With a copy to:

Vice President, Chief Financial Officer and Comptroller

Gulf Power Company

1 Energy Place

Pensacola, FL 32520

Facsimile:  (850) 444-6744

and if given to FPUC, it shall be addressed to:

President and CEO

Florida Public Utilities Company

401 S. Dixie Highway

West Palm Beach, FL 33401

Facsimile: (561) 833-8562

unless Gulf Power or FPUC shall have designated a different officer or address for itself by appropriate notice to the other.

17.12

Counterparts.  This Agreement may be executed in multiple counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.

17.13

Articles and Sections Headings.  The descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms or provisions hereof.

17.14

Public Announcement.  The Parties agree that no public or other announcement concerning the detailed terms and conditions or pricing provisions hereof shall be made except after mutual consultation and consent; provided, however, that consent will not be required if either Party determines that disclosure is required by a Governmental Authority.

17.15

Governing Law.  The Agreement shall be governed by and construed in accordance with the laws of the State of Florida.

17.16

Information Exchange.  The implementation and administration of this Agreement may require FPUC to provide certain information relating to FPUC’s historical and projected loads, and any other necessary information as determined by the Parties (“FPUC Information”).  Such FPUC Information may be provided to Southern Company Generation (“SCGen”), a division of SCS as agent for Gulf Power.  SCGen includes “energy affiliates” of the Southern Operating Companies as defined by FERC’s Standards of Conduct regulations.  FPUC understands that SCGen will only use FPUC Information for the limited purpose of implementing and administering this Agreement, and for no other purpose, and that such information will not be used or disseminated in any manner contrary to the confidentiality provisions in Article 15 of this Agreement or in violation of FERC’s Standards of Conduct.  

FPUC acknowledges that FPUC Information has not been and is not being provided to SCGen in exchange for any preferential treatment, either operational or rate-related, by Gulf Power.  

17.17

Severability.  In the event any provision of this Agreement is declared invalid or unenforceable by a final, non-appealable order of any Governmental Authority, the Parties shall promptly renegotiate to restore this Agreement as near as possible to its original intent and effect.

17.18

Further Assurances.  If either Party reasonably determines or is reasonably advised that any further instruments or any other things are necessary or desirable to carry out the terms of this Agreement, the other Party shall execute and deliver all such instruments and assurances and do all things reasonably necessary and proper to carry out the terms of this Agreement.

17.19

Entire Agreement.  This Agreement and the Appendices attached hereto constitute the entire agreement between the Parties as of the time of execution relating to the subject matter contemplated by this Agreement and supersedes all prior agreements, whether oral or written.

17.20

Survival of Obligations.  Upon the expiration or termination of the Parties’ sale, purchase and delivery obligations under this Agreement, any monies, penalties or other charges due and owing Gulf Power or subsequently becoming due and owing (including the Monthly Energy Payment and Monthly Capacity Payment for the last Month of the Service Term and the true-up amounts calculated under Appendix C) shall be paid in accordance with the terms of this Agreement, any corrections or adjustments to payments previously made shall be determined, and any refunds due FPUC made, as soon as practicable.   To the extent necessary to enforce or resolve matters or claims hereunder, the provisions of Articles 4, 6, 9, 10, 12, 13, 16 and Sections 2.2, 17.6, 17.7 and 17.8, including the rights and obligations of the Parties therein provided, shall survive the termination or expiration of this Agreement and the performance by the Parties of their obligations hereunder.

17.21

Changes in Agreement. Except for any changes and/or a termination of this Agreement pursuant to Section 9.3.1, absent the agreement of the Parties to the proposed change, the standard of review for changes to this contract proposed by a Party, a non-Party or FERC acting sua sponte shall be the "public interest" standard of review set forth in United Gas Pipeline Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the "Mobile-Sierra" doctrine).

[The next page is the signature page.]

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed and delivered by their respective duly authorized representatives as of the date first above written.

GULF POWER COMPANY

By its Agent

Southern Company Services, Inc.

By:_________________________________

Name:

Title:

FLORIDA PUBLIC UTILITIES COMPANY

By:_________________________________

Name:

Title:

APPENDIX A

CAPACITY PURCHASE

Commencing in 2007 and in each subsequent Year through 2016 (each a “Calculation Year”), prior to November 1, Gulf Power (or its designated agent) shall calculate the Northwest Annual Peak Demand, the Growth Rate, the Forecasted Northwest Annual Peak Demand, and the Capacity Purchase for the following Year, all in accordance with this Appendix A.  Prior to October 15 of each Calculation Year, FPUC shall provide Gulf Power (or its designated agent) with all information FPUC possesses (with supporting documentation) that is necessary for these calculations.

A.

Northwest Annual Peak Demand.

Gulf Power or its agent shall calculate the Northwest Annual Peak Demand for each of the four previous Peak Seasons, including the Peak Season of the Calculation Year (each a “Previous Season”).

B.

Growth Rate.

Gulf Power or its agent shall calculate the growth rate of the Northwest Annual Peak Demand from the average annual growth rate of the Northwest Annual Peak Demand (“Growth Rate”).  The Growth Rate shall be rounded to four (4) decimal places, and shall be the quotient of:

(1)

the sum of:

(a)

the Northwest Annual Peak Demand for the third prior Previous Season divided by the Northwest Annual Peak Demand for the fourth prior Previous Season, minus one (1); plus

(b)

the Northwest Annual Peak Demand for the second prior Previous Season divided by the Northwest Annual Peak Demand for the third prior Previous Season Year, minus one (1); plus

(c)

the Northwest Annual Peak Demand for the first prior Previous Season divided by the Northwest Annual Peak Demand for the second prior Previous Season, minus one (1).

(2)

divided by three (3).

C.

Forecasted Northwest Annual Peak Demand.  

The Forecasted Northwest Annual Peak Demand shall be rounded to the nearest kilowatt (kW), and shall be the higher result of either:

(1)

the Northwest Annual Peak Demand for the third prior Previous Season, plus the Northwest Annual Peak Demand for the second prior Previous Season, plus the Northwest Annual Peak Demand for the first prior Previous Season; divided by

(2)

three (3); multiplied by

(3)

the square of the sum of one (1) plus the Growth Rate,

or

(1)

the Northwest Annual Peak Demand for the second prior Previous Season plus the Northwest Annual Peak Demand for the first prior Previous Season; divided by

(2)

two (2).

D.

Capacity Purchase.  

The Capacity Purchase for the Year following the Calculation Year shall be rounded to the nearest kilowatt (kW), and shall be the greater of:

(1)

the lesser of :

(a)

the product of:

(i)

the Reserve Requirement plus one (1); multiplied by the

(ii)

Forecasted Northwest Annual Peak Demand.

Or

(b)

the product of:

(i)

one and one-hundredth (1.01) plus the Growth Rate; multiplied by the

(ii)

Capacity Purchase for the Calculation Year.

Or

(2)

the Capacity Purchase for the Calculation Year.

Notwithstanding the foregoing, the Capacity Purchase for Year 2008 shall be equal to the product of: (i) the Reserve Requirement plus one (1); multiplied by (ii) the Forecasted Northwest Annual Peak Demand.

E.

Reductions in Capacity Purchase.

If in any Year of the Service Term FPUC is required to purchase capacity from a third party under applicable Law pursuant to Section 3.4(ii) or (iii) and the Parties cannot agree upon feasible actions (if any) to be taken by either or both Parties such that FPUC can satisfy and/or comply with such Law for such Year while simultaneously leaving this Agreement in full force and effect as originally executed, then the Capacity Purchase calculated for such Year (or applicable portion thereof) pursuant to the provisions of this Appendix A shall be reduced by such amount necessary for FPUC to comply with applicable Law.  In addition, if during the Service Term, (i) FPUC’s franchise agreement with the City of Marianna, Florida expires and is not renewed, extended or replaced, and (ii) Gulf Power and/or any of its

Affiliates sells electric capacity to the City of Marianna, then for the period of time that Gulf Power and/or its Affiliates sells capacity to the City of Marianna, the Capacity Purchase to FPUC shall be reduced by the amount of capacity sold to the City of Marianna by Gulf Power and/or its Affiliates.    

F.

Example Calculation.

An example calculation of the Capacity Purchase is set forth in Exhibit 1 to this Appendix A.  Such calculation is for example purposes only and is not intended to, and shall not, modify any of the terms of this Agreement (including the above terms of this Appendix A).  To the extent that there is a conflict between this example and such terms of this Agreement, such terms of this Agreement shall govern.  Moreover, such example shall be given no weight in interpreting or construing the provisions of this Agreement (including the methodology set forth above in this Appendix A).

Exhibit 1

Example Calculation of Capacity Purchase

Note: All data is for example purposes only, and is not representative of actual or forecasted data.            

Calculation Year = 2005

A. Marianna Annual Peak Demand

Year	Peak Season MW	Transmission Loss Factor	Peak Season MW (after loss adj.)
2002	71.798	0.026%	73.715
2003	66.281	0.026%	68.050
2004	69.653	0.026%	71.512
2005	74.411	0.026%	76.397

Peak Season is defined as May through September

B. Growth Rate

(1)	(a)		-7.69%
	(b)		5.09%
	(c)	+	6.83%
			4.23%

(2) 4.23% / 3 = 1.41%... rounded to 4 decimal places

C. Forecasted Marianna Annual Peak Demand

(1)	215.959	or	(1)	147.909
(2)	71.986		(2)	73.955*	Assumed Previous Year Capacity Purchase
(3)	74.030*				84.041 (for example purposes only)
*Highest Amount 74.05

D. Capacity Purchase

(1)	(a)	(i)	1.15	or	(b)	(i)	1.0241
		(ii)	85.135*			(ii)	86.066*
	* Least amount 85.135**
(2)			84.041**
	**85.135   Highest amount
2006 Capacity Purchase: 85.135 MW

APPENDIX B

MONTHLY CAPACITY PAYMENT

The Monthly Capacity Payment, in dollars ($), shall be calculated for each Month of the Service Term and shall equal the product of:

(1)

the Capacity Purchase for the applicable Year as calculated in Appendix A, in kilowatts (kW); multiplied by

(2)

the Monthly Capacity Rate.

APPENDIX C

GULF ENERGY RATE

Prior to the beginning of each Year of the Service Term (each such Year being referred to as an “Applicable Year”), Gulf Power shall calculate and establish the Gulf Energy Rate for the Applicable Year and notify FPUC of such rate (the Year prior to the Applicable Year shall be referred to as the “Current Year”, and the Year prior to the Current Year shall be referred to as the “Previous Year”).  The Gulf Energy Rate shall be calculated for each Applicable Year as set forth below and shall be rounded to five decimal places:

Gulf

Energy Rate =

the sum of the following:

(1) [(Projected Fuel Related Cost / Projected Territorial MWH Sales) * Line Loss Multiplier] + (FPUC Fuel True-Up / Projected FPUC MWH Sales); plus

(2) [(Projected Environmental Related Cost / Projected Territorial MWH Sales) * Line Loss Multiplier] + (FPUC Environmental True-Up / Projected FPUC MWH Sales)

Where:

Projected Fuel

Related Cost =

Gulf Power’s estimate of the Fuel Related Cost for the Applicable Year.  

Fuel Related Cost =

The sum of the following amounts for a given period of time, each as determined by Gulf Power: (i) the cost of fuel issued from FERC Account 151 (or a successor account(s)) of the Federal Energy Regulatory Commission’s Uniform System of Accounts with respect to Gulf Power’s generating and power supply resources, including fuel transportation costs (firm and non-firm) and fuel storage; plus (ii) variable operation and maintenance costs (including fuel handling) with respect to Gulf Power’s generating and power supply resources (as variable operation and maintenance costs are defined in applicable FERC accounts, provided that if the FERC accounts are modified such that a cost formerly included within such definition(s) is no longer included, such cost shall be deemed to remain within

Fuel Related Cost hereunder); plus (iii) the cost of energy purchases made by, for, or on behalf of Gulf Power, including transmission and other costs related to such energy purchases; plus (iv) hedging costs, including gains and losses, associated with hedging fuel purchased or consumed by Gulf Power; plus (v) Gulf Power’s costs associated with buy-outs and buy-downs of fuel contracts; less (vi) Gulf Power’s fuel and emissions allowance revenues related to non-territorial sales.    

Projected

Environmental

Related Cost =

Gulf Power’s estimate of the Environmental Related Cost for the Applicable Year.  

Environmental

Related Cost =

Environmental related costs that will be recovered during a given period of time through Gulf Power’s retail environmental cost recovery clause pursuant to the review and approval of the FPSC.  The Environmental Related Cost shall consist of the sum of the following amounts, each as determined by Gulf Power: (i) an overall rate of return on net investment and working capital (calculated using the capital structure and cost rates approved for Gulf Power by the FPSC); plus (ii) depreciation expense on investment ; plus (iii) operation and maintenance costs; plus (iv) ad valorem taxes; plus (v) the emissions allowance expenses associated with the consumption of fuel, less gains to Gulf Power from its sale of emissions allowances to non-Affiliates of Gulf Power to the extent that such sales are made during the Service Term (such gains shall equal revenues less the costs associated with the allowances sold); plus (vi) any other amounts allowed to be recovered through Gulf Power’s retail environmental cost recovery clause by the FPSC.  Provided, however, notwithstanding anything to the contrary in this Agreement, in the event that the methodology for determining the costs that Gulf Power recovers through the retail environmental cost recovery clause is modified after the Effective Date (including modification of the types of costs that Gulf Power recovers under such clause), the capacity and/or energy rates in this Agreement shall be modified as required in order for Gulf Power to receive full recovery for the types of costs that were previously recoverable through the retail environmental cost recovery clause.    

Projected

Territorial

MWH Sales =

Gulf Power’s estimate of Territorial MWH Sales for the Applicable Year.

Territorial

MWH Sales =

For a given period of time, Gulf Power’s territorial energy sales for such period.

Line Loss

Multiplier =

The wholesale energy loss factor for the Applicable Year to adjust for applicable line losses back to Gulf Power’s electricity resources, as calculated by Gulf Power.

Projected

FPUC MWH

Sales =

Gulf Power’s estimate of FPUC MWH Sales for the Applicable Year.

FPUC

MWH Sales =

For a given period of time, the aggregate Delivered Energy for all hours during such period.

FPUC Fuel

True-Up =

The sum of the Final Fuel True-Up (including interest) plus the Estimated Fuel True-Up (including interest); provided, however, that: (i) the FPUC Fuel True-Up for the first Applicable Year of the Service Term shall be deemed equal to zero (0); and (ii) the FPUC Fuel True-Up for the second Applicable Year of the Service Term shall be deemed equal to the Estimated Fuel True-Up for such Applicable Year.

Estimated Fuel

True-Up  =

The difference of the following amounts, each as estimated by Gulf Power: (i) the total Fuel Related Cost for the Current Year associated with FPUC MWH Sales for the Current Year; minus (ii) the revenues associated with Fuel Related Cost for the Current Year that Gulf Power has or will receive through FPUC MWH Sales for the Current Year.  The Estimated Fuel True-Up shall be calculated utilizing actual data for the Current Year to the extent it is available, and estimated data to the extent actual data is not available.  The Estimated Fuel True-Up shall include interest (as calculated below) on the average over/under-recovery balance of costs.    

Final Fuel

True-Up =

The difference of: (i) the total actual Fuel Related Cost for the Previous Year associated with FPUC MWH Sales for the Previous Year minus the revenues associated with Fuel Related Cost for the Previous Year that Gulf Power received through FPUC MWH Sales for the Previous Year; minus (ii) the Estimated Fuel True-Up for the Previous Year.  The Final Fuel True-Up shall include interest (as calculated below) on the average over/under-recovery balance of costs.  

FPUC

Environmental

True-Up =

The sum of the Final Environmental True-Up (including interest) plus the Estimated Environmental True-Up (including interest); provided, however, that: (i) the FPUC Environmental True-Up for the first Applicable Year of the Service Term shall be deemed equal to zero (0); and (ii) the FPUC Environmental True-Up for the second Applicable Year of the Service Term shall be deemed equal to the Estimated Environmental True-Up for such Applicable Year.

Estimated

Environmental

True-Up =

The difference of the following amounts, each as estimated by Gulf Power: (i) the total Environmental Related Cost for the Current Year associated with FPUC MWH Sales for the Current Year; minus (ii) the revenues associated with Environmental Related Cost for the Current Year that Gulf Power has or will receive through FPUC MWH Sales for the Current Year.   The Estimated Environmental True-Up shall be calculated utilizing actual data for the Current Year to the extent it is available, and estimated data to the extent actual data is not available.  The Estimated Environmental True-Up shall include interest (as calculated below) on the average over/under-recovery balance of costs.     

Final Environmental

True-Up =

The difference of: (i) the total actual Environmental Related Cost for the Previous Year associated with FPUC MWH Sales for the Previous Year minus the revenues associated with Environmental Related Cost for the Previous Year that Gulf Power received through FPUC MWH Sales for the Previous Year; minus (ii) the Estimated Environmental True-Up for the Previous Year.  The Final Environmental True-Up shall include interest (as calculated below) on the average over/under-recovery balance of costs.  

For purposes of calculating interest to be included within the true-up amounts calculated above, interest will be computed monthly on the average over/under-recovery balance of costs (which balance shall be based on the difference between Fuel Related Costs and Environmental Related Costs (as applicable) and the revenues associated with such costs that have been or will be received by Gulf Power), utilizing the 30-day commercial paper rate for high grade, unsecured notes, sold through dealers by major corporations as regularly published in the Wall Street Journal.  For each Month, the interest rate to be applied for that Month shall be equal to the simple average of such annual rate as published on the first business Day of such Month and such annual rate as published on the first business Day of the subsequent Month.  The interest calculated shall be added to the over/under-recovery balance of costs.  

After the conclusion of the Service Term, Gulf Power shall issue additional subsequent invoices to FPUC for the true-up amounts that would have otherwise been reflected in the Gulf Energy Rate and the Monthly Energy Payment for subsequent Years as if the Agreement had been renewed or extended for such Years under the same terms.  The timing for the issuance of such invoices shall be consistent with the timing for the calculation of such true-up amounts under this Agreement.  FPUC recognizes that its payment of such true-up amounts (in the case of an under-recovery) will be necessary for Gulf Power to be fully compensated for providing service under the terms of this Agreement.  Accordingly, in the event that such true-up amounts calculated and invoiced are positive, FPUC shall pay such amounts, as and when invoiced, pursuant to the provisions of this Agreement.  Provided, however, in the event a net over-recovery exists after the Final Environmental True-Up and the Final Fuel True-Up are calculated (based on actual data) for the final Year of the Service Term, Gulf Power shall pay FPUC the amount of any net over-recovery.

APPENDIX D

MONTHLY ENERGY PAYMENT

For each Month of the Service Term, the Monthly Energy Payment (in dollars per Month ($/Mo.)) shall be equal to the summation, for all Hours of such Month, of the Gulf Energy Cost determined as follows:

The Gulf Energy Cost, in dollars ($) rounded to the nearest one cent (¢), for a given Hour, shall equal the product of:

(1)  the Gulf Energy Rate for the Applicable Year in which such Hour occurs; multiplied by

(2)  the Delivered Energy for such Hour.

APPENDIX E

FORM OF COMPLIANCE CERTIFICATE

Date:  ______________ ___, 200_____

TO:

RE:

Requirements Service Agreement dated as of ___________ ____, 2006 among Gulf Power Company and Florida Public Utilities Company (as the same may be amended, modified, extended or restated from time to time, the “Agreement”)

Pursuant to the terms of the Agreement, I, _________________________, Chief Financial Officer of _______________________, hereby certify that, as of the fiscal quarter ending ______________ ___, 20_____, the statements and calculations below are accurate and complete in all respects (all capitalized terms used below shall have the meanings set forth in the Agreement):

1.

Funds from Operations Interest Coverage Ratio for _________________:

a.

Net Income from Continuing Operations

$

b.

Depreciation and Amortization

$

c.

Deferred Income Taxes

$

d.

Gross Interest Expense incurred before subtracting

$

capitalized interest and interest income

e.

Ratio of (Net Income from Continuing Operations

 :

+ Depreciation and Amortization + Deferred

Income Taxes + Gross Interest Expense incurred

before subtracting capitalized interest and interest

income) / Gross Interest Expense incurred before

subtracting capitalized interest and interest income

Minimum Required:  2.0 : 1.0, as tested quarterly as of the end of each quarter averaged over the six (6) consecutive quarters then ending.

2.

Total Debt to Total Capital Ratio for ______________:

a.

Long Term Debt

$

b.

Current Maturities

$

c.

Commercial Paper

$

d.

Other Short Term Borrowings

$

e.

Shareholder’s Equity (Including Preferred)

$

f.

Minority Interest

$

g.

Ratio of (Long Term Debt + Current Maturities

 :

+ Commercial Paper + Other Short Term

Borrowings) / (Long Term Debt + Current

Maturities + Commercial Paper + Other Short

Term Borrowings + Shareholder’s Equity Including

Preferred + Minority Interest)

Maximum Allowed:  .65 : 1.0, as tested quarterly as of the end of each quarter averaged over the six (6) consecutive quarters then ending.

3.

__________ has the Required Ratios and no Event of Default exists with respect to ______________ except as indicated on a separate page attached hereto, together with an explanation of the action taken or proposed to be taken by ________ with respect thereto.

_________

By:

___

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Florida Public Utilities Company

West Palm Beach Florida

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No.333- 63532) and on Form S-8 (No. 333-63942), Form S-8 (No. 333-125551) Form S-8 (No. 333-124554) of Florida Public Utilities Company of our report dated March 16, 2007, relating to the consolidated financial statements, which appear in this Form 10-K.

BDO Seidman, LLP

West Palm Beach, Florida

March 16, 2007

EX-31

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

FLORIDA PUBLIC UTILITIES COMPANY

(Section 302)

I, John T. English, certify that:

1.

I have reviewed this annual report on Form 10-K of Florida Public Utilities Company (the “registrant”);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 19, 2007

By /s/ John T. English

John T. English

Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

FLORIDA PUBLIC UTILITIES COMPANY

(Section 302)

I, George M. Bachman, certify that:

1.

I have reviewed this annual report on Form 10-K of Florida Public Utilities Company (the “registrant”);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 19, 2007

By /s/ George M. Bachman

George M. Bachman

Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report on Form 10-K of Florida Public Utilities Company (the "Company") for the period ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the "Form 10-K"), we, John T. English, Chief Executive Officer and George M. Bachman, Chief Financial Officer of the Company, certify, to the best of our knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John T. English

John T. English

Chief Executive Officer

March 19, 2007

/s/ George M. Bachman

George M. Bachman

Chief Financial Officer

March 19, 2007