10-Q 1 d10q.htm FORM 10-Q Form 10-Q

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

or

 

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

For the transition period from              to             

 

Commission File No.   Exact name of each Registrant as specified in its
charter, state of incorporation, address of principal
executive offices, telephone number
 

I.R.S. Employer

Identification Number

1-8180  

TECO ENERGY, INC.

(a Florida corporation)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(813) 228-1111

  59-2052286
1-5007  

TAMPA ELECTRIC COMPANY

(a Florida corporation)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(813) 228-1111

  59-0475140

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

 

Title of each class   Name of each exchange on which registered
TECO Energy, Inc.  
Common Stock, $1.00 par value   New York Stock Exchange
Common Stock Purchase Rights   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the registrants (1) have 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) have been subject to such filing requirements for the past 90 days.    YES  x    NO  ¨

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

Large accelerated filer  x Accelerated filer  ¨ Non-accelerated filer  ¨ Smaller reporting company  ¨

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

Large accelerated filer  ¨ Accelerated filer  ¨ Non-accelerated filer  x Smaller reporting company  ¨

Indicate by check mark whether TECO Energy, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Apr. 25, 2008 was 210,755,868. As of Apr. 25, 2008, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (H) (1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

This combined Form 10-Q represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes representations only as to information relating to itself and its subsidiaries.

Page 1 of 48

Index to Exhibits appears on page 48


PART I. FINANCIAL INFORMATION

 

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Mar. 31, 2008 and Dec. 31, 2007, and the results of their operations and cash flows for the periods ended Mar. 31, 2008 and 2007. The results of operations for the three month period ended Mar. 31, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008. References should be made to the explanatory notes affecting the consolidated financial statements contained in Amendment No. 1 to TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2007 and to the notes on pages 8 through 22 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

     Page No.

Consolidated Condensed Balance Sheets, Mar. 31, 2008 and Dec. 31, 2007

   3-4

Consolidated Condensed Statements of Income for the three month periods ended Mar. 31, 2008 and 2007

   5

Consolidated Condensed Statements of Comprehensive Income for the three month periods ended Mar. 31, 2008 and 2007

   6

Consolidated Condensed Statements of Cash Flows for the three month periods ended Mar. 31, 2008 and 2007

   7

Notes to Consolidated Condensed Financial Statements

   8-22

 

2


TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

Assets    Mar. 31,     Dec. 31,  

(millions, except for share amounts)

   2008     2007  

Current assets

    

Cash and cash equivalents

   $ 118.1     $ 162.6  

Restricted cash

     7.5       7.4  

Short-term investments

     2.3       —    

Receivables, less allowance for uncollectibles of $3.5 and $3.3 at Mar. 31, 2008 and Dec. 31, 2007, respectively

     309.9       295.9  

Crude oil options receivable, net

     —         78.5  

Inventories, at average cost

    

Fuel

     78.7       85.8  

Materials and supplies

     68.1       68.2  

Current regulatory assets

     55.3       67.4  

Current derivative assets

     72.2       0.3  

Prepayments and other current assets

     21.9       23.0  

Income tax receivables

     0.7       0.7  
                

Total current assets

     734.7       789.8  
                

Property, plant and equipment

    

Utility plant in service

    

Electric

     5,256.9       5,275.2  

Gas

     925.4       917.4  

Construction work in progress

     427.2       364.8  

Other property

     344.6       336.4  
                

Property, plant and equipment

     6,954.1       6,893.8  

Accumulated depreciation

     (2,001.8 )     (2,005.6 )
                

Total property, plant and equipment, net

     4,952.3       4,888.2  
                

Other assets

    

Deferred income taxes

     416.3       424.9  

Other investments

     22.0       22.9  

Long-term regulatory assets

     186.7       186.8  

Long-term derivative assets

     8.4       1.9  

Investment in unconsolidated affiliates

     246.0       275.5  

Goodwill

     59.4       59.4  

Deferred charges and other assets

     116.6       115.8  
                

Total other assets

     1,055.4       1,087.2  
                

Total assets

   $ 6,742.4     $ 6,765.2  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

3


TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

 

Liabilities and Capital    Mar. 31,     Dec. 31,  

(millions, except for share amounts)

   2008     2007  

Current liabilities

    

Long-term debt due within one year

    

Recourse

   $ 5.7     $ 5.7  

Non-recourse

     1.4       1.4  

Notes payable

     18.0       25.0  

Accounts payable

     282.2       302.1  

Customer deposits

     141.1       138.1  

Current regulatory liabilities

     102.9       35.4  

Current derivative liabilities

     16.3       26.0  

Interest accrued

     65.4       32.7  

Taxes accrued

     34.5       33.2  

Other current liabilities

     15.3       18.0  
                

Total current liabilities

     682.8       617.6  
                

Other liabilities

    

Investment tax credits

     11.4       12.2  

Long-term regulatory liabilities

     590.8       582.7  

Long-term derivative liabilities

     0.1       0.1  

Deferred credits and other liabilities

     402.2       377.2  

Long-term debt, less amount due within one year

    

Recourse

     3,054.4       3,149.4  

Non-recourse

     7.7       9.0  
                

Total other liabilities

     4,066.6       4,130.6  
                

Commitments and contingencies (see Note 10)

    

Capital

    

Common equity (400.0 million shares authorized; par value $1; 210.7 million shares and 210.9 million shares outstanding at Mar. 31, 2008 and Dec. 31, 2007, respectively)

     210.7       210.9  

Additional paid in capital

     1,493.1       1,489.2  

Retained earnings

     323.8       334.1  

Accumulated other comprehensive loss

     (34.6 )     (17.2 )
                

Total capital

     1,993.0       2,017.0  
                

Total liabilities and capital

   $ 6,742.4     $ 6,765.2  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

4


TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

     Three months ended Mar. 31,  

(millions, except per share amounts)

   2008     2007  

Revenues

    

Regulated electric and gas (includes franchise fees and gross receipts taxes of $26.4 in 2008 and $27.0 in 2007)

   $ 640.2     $ 640.6  

Unregulated

     151.5       180.7  
                

Total revenues

     791.7       821.3  
                

Expenses

    

Regulated operations

    

Fuel

     163.6       189.1  

Purchased power

     81.9       53.6  

Cost of natural gas sold

     119.0       107.7  

Other

     71.3       57.6  

Operation other expense

    

Mining related costs

     107.2       94.5  

Waterborne transportation costs

     —         54.7  

Other

     4.3       3.5  

Maintenance

     46.0       49.0  

Depreciation and amortization

     65.0       71.6  

Taxes, other than income

     54.9       58.8  

Gain on sale, net of transaction related costs

     0.9       2.8  
                

Total expenses

     714.1       742.9  
                

Income from operations

     77.6       78.4  
                

Other income

    

Allowance for other funds used during construction

     1.3       1.7  

Other income

     5.3       51.9  

Income from equity investments

     17.4       16.2  
                

Total other income

     24.0       69.8  
                

Interest charges

    

Interest expense

     58.2       67.8  

Allowance for borrowed funds used during construction

     (0.5 )     (0.7 )
                

Total interest charges

     57.7       67.1  
                

Income before provision for income taxes

     43.9       81.1  

Provision for income taxes

     13.1       31.8  
                

Income before minority interest

     30.8       49.3  

Minority interest

     —         23.5  
                

Net income

   $ 30.8     $ 72.8  
                

Average common shares outstanding – Basic

     209.7       208.6  

                                                                 – Diluted

     210.6       209.6  
                

Earnings per share – Basic

   $ 0.15     $ 0.35  

                                  – Diluted

   $ 0.15     $ 0.35  
                

Dividends paid per common share outstanding

   $ 0.195     $ 0.190  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

5


TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

 

     Three months ended Mar. 31,

(millions)

   2008     2007

Net income

   $ 30.8     $ 72.8
              

Other comprehensive income (loss), net of tax

    

Net unrealized (losses) gains on cash flow hedges

     (5.9 )     1.9

Amortization of unrecognized benefit costs

     0.3       0.4

Change in benefit obligations due to remeasurement

     (10.8 )     —  

Unrealized loss on available-for-sale securities

     (1.0 )     —  
              

Other comprehensive (loss) income, net of tax

     (17.4 )     2.3
              

Comprehensive income

   $ 13.4     $ 75.1
              

The accompanying notes are an integral part of the consolidated condensed financial statements

 

6


TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

 

     Three months ended Mar. 31,  

(millions)

   2008     2007  

Cash flows from operating activities

    

Net income

   $ 30.8     $ 72.8  

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

    

Depreciation

     65.0       71.6  

Deferred income taxes

     15.5       29.3  

Investment tax credits, net

     (0.7 )     (0.6 )

Allowance for funds used during construction

     (1.3 )     (1.7 )

Non-cash stock compensation

     2.4       2.5  

Loss on sale of business/assets

     (1.0 )     (24.3 )

Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings

     14.8       4.8  

Minority interest

     —         (23.5 )

Derivatives

     —         (18.8 )

Deferred recovery clause

     (11.4 )     12.8  

Receivables, less allowance for uncollectibles

     (13.1 )     15.7  

Inventories

     7.2       (42.2 )

Prepayments and other deposits

     1.0       1.8  

Taxes accrued

     1.3       29.4  

Interest accrued

     32.7       35.8  

Accounts payable

     (5.6 )     (36.4 )

Other

     15.4       29.9  
                

Cash flows from operating activities

     153.0       158.9  
                

Cash flows from investing activities

    

Capital expenditures

     (136.9 )     (134.5 )

Allowance for funds used during construction

     1.3       1.7  

Net proceeds from sale of business/assets

     (7.3 )     7.9  

Distributions from unconsolidated affiliates

     13.2       14.0  

Other investments

     76.3       (43.8 )
                

Cash flows used in investing activities

     (53.4 )     (154.7 )
                

Cash flows from financing activities

    

Dividends

     (41.1 )     (39.8 )

Proceeds from the sale of common stock

     1.3       3.6  

Proceeds from long-term debt

     190.8       —    

Repayment of long-term debt/Purchase in lieu of redemption

     (288.1 )     (72.8 )

Minority interest

     —         21.8  

Net (decrease) increase in short-term debt

     (7.0 )     3.0  
                

Cash flows used in financing activities

     (144.1 )     (84.2 )
                

Net decrease in cash and cash equivalents

     (44.5 )     (80.0 )

Cash and cash equivalents at beginning of period

     162.6       441.6  
                

Cash and cash equivalents at end of period

   $ 118.1     $ 361.6  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

7


TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries, and the accounts of variable interest entities for which it is the primary beneficiary (TECO Energy or the company). All significant intercompany balances and intercompany transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy is not the primary beneficiary but we are able to exert significant influence. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Mar. 31, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Mar. 31, 2008 and 2007. The results of operations for the three month period ended Mar. 31, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates. The year end condensed balance sheet data was derived from audited financial statements, however this quarterly report on Form 10-Q does not include all year end disclosures required for an annual report on Form 10-K by GAAP in the United States of America.

Revenues

As of Mar. 31, 2008 and Dec. 31, 2007, unbilled revenues of $46.5 million and $46.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Cash Flows Related to Derivatives and Hedging Activities

The company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of heating oil swaps that are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operations section. For natural gas and interest rate swaps, the cash inflows and outflows are also included in the operating section. For the year ended Dec. 31, 2007, crude oil options that protected the cash flows related to the sales of investor interests in the synthetic fuel production facilities were included in the investing section.

Other Income and Minority Interest

In 2007, TECO Energy earned a portion of its income indirectly through the synthetic fuel operations at TECO Coal. At Mar. 31, 2007, TECO Coal had sold ownership interests in the synthetic fuel facilities to unrelated third-party investors equal to 98%. These investors paid for the purchase of the ownership interests as synthetic fuel was produced. The payments were based on the amount of production and sales of synthetic fuel and the related underlying value of the tax credit, which was subject to potential limitation based on the price of domestic crude oil. These payments were recorded in “Other income” in the Consolidated Condensed Statements of Income. Additionally, the outside investors made payments towards the cost of producing synthetic fuel. These payments were reflected as a benefit under “Minority interest” in the Consolidated Condensed Statements of Income, and comprised the majority of that line item. The synthetic fuel operations were terminated on Dec. 31, 2007 concurrent with the termination of the tax credit program.

For the three month period ended Mar. 31, 2008, “Other income” included the final adjustment of $0.9 million to the 2007 inflation factor applied to the tax credit available on the production of synthetic fuel in 2007. For the three month period ended Mar. 31, 2007, “Other income” also included an estimated phase-out of approximately 14%, or $6.6 million pretax, of the benefit of the underlying value of the tax credit based on the internal estimate of the average annual price of domestic crude oil during the first three months of 2007.

Purchased Power

Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $81.9 million and $53.6 million for the three months ended Mar. 31, 2008 and 2007, respectively. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC) approved cost recovery clauses.

 

8


Accounting for Franchise Fees and Gross Receipts

The regulated utilities (Tampa Electric and Peoples Gas System (PGS)) are allowed to recover from customers certain costs incurred through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. These amounts totaled $26.4 million and $27.0 million, respectively, for the three months ended Mar. 31, 2008 and 2007. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These totaled $26.2 million and $26.9 million, respectively, for the three months ended Mar. 31, 2008 and 2007, respectively.

2. New Accounting Pronouncements

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 161, Disclosures about Derivative Instruments and Hedging Activities (FAS 161). FAS 161 was issued to enhance the disclosure framework in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). FAS 161 requires enhanced disclosures about the purpose of an entity’s derivative instruments, how derivative instruments and hedged items are accounted for, and how the entity’s financial position, cash flows, and performance are enhanced by the derivative instruments and hedged items. The guidance in FAS 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. The company does not believe FAS 161 will be material to its results of operations, statement of position or cash flows.

Accounting for Transfers of Financial Assets and Repurchase Financing Transactions

In February 2008, the FASB issued FASB Staff Position (FSP) No. 140-3, Accounting for Transfers of Financial Assets and Repurchase Financing Transactions (FSP 140-3). FSP 140-3 provides guidance when a company enters an agreement (or linked agreements) to transfer a financial asset and establish a repurchase financing. FSP 140-3 prohibits separately accounting for the initial transfer and the repurchase financing unless certain criteria are met. The guidance in FSP 140-3 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. The company does not believe FSP 140-3 will be material to its results of operations, statement of position or cash flows.

Statement 133 Implementation Issue E23

In January 2008, the FASB cleared Implementation Issue Hedging – General: Issues Involving the Application of the Shortcut Method under Paragraph 68 (Issue E23). Issue E23 amends FAS 133, paragraph 68 to include hedged items with trade dates differing from their settlement dates due to generally established conventions in the marketplace. This allows companies to assume these commitments have no ineffectiveness in a hedging relationship, thus allowing use of the shortcut method for accounting purposes assuming all other conditions within the paragraph are met.

Issue E23 also allows use of the shortcut method if the fair value of an interest rate swap is not zero at inception of the hedge as long as the swap was entered into at the relationship’s inception, there was no transaction price of the swap in the company’s principal or most advantageous market, and the difference between the swap’s fair value and transaction price is due to differing prices within the bid-ask spread between the entry transaction and a hypothetical exit transaction.

The effective date for Issue E23 is for hedging relationships entered into on or after Jan. 1, 2008. The company does not believe Issue E23 will be material to its results of operations, statement of position or cash flows.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (FAS 160). FAS 160 was issued to improve the relevance, comparability and transparency of the financial information provided by requiring: ownership interests be presented in the consolidated statement of financial position separate from parent equity; the amount of net income attributable to the parent and the noncontrolling interest be identified and presented on the face of the consolidated statement of income; changes in the parent’s ownership interest be accounted for consistently; when deconsolidating, that any retained equity interest be measured at fair value; and that sufficient disclosures identify and distinguish between the interests of the parent and noncontrolling owners. The guidance in FAS 160 is effective for fiscal years beginning on or after Dec. 15, 2008. The company is currently assessing the impact of FAS 160, but does not believe it will be material to its results of operations, statement of position or cash flows.

Business Combinations (Revised)

In December 2007, the FASB issued SFAS No. 141R, Business Combinations (FAS 141R). FAS 141R was issued to improve the relevance, representational faithfulness, and comparability of information disclosed in financial statements about business combinations. The Statement establishes principles and requirements for how the acquirer: 1) recognizes and measures the assets acquired, liabilities assumed and any noncontrolling interest in the acquiree; 2) recognizes and measures the goodwill acquired; and 3) determines what information to disclose for users of financial statements to evaluate the effects

 

9


of the business combination. The guidance in FAS 141R is effective prospectively for any business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after Dec. 15, 2008. The company will assess the impact of FAS 141R in the event it enters into a business combination whose expected acquisition date is subsequent to the required adoption date.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FASB Staff Position (FSP) FIN 39-1. This FSP amends FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts by allowing an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The guidance in this FSP is effective for fiscal years beginning after Nov. 15, 2007. The company adopted this FSP effective Jan. 1, 2008 and as of Mar. 31, 2008 did not hold or give collateral.

Fair Value Option For Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of FAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. FAS 159 is effective for fiscal years beginning after Nov. 15, 2007. The company adopted FAS 159 effective Jan. 1, 2008, but did not elect to measure any financial instruments at fair value. Accordingly, its adoption did not have any effect on its results of operations, statement of position or cash flows.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value, and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. SFAS 157 defines the following fair value hierarchy, based on these two types of inputs:

 

   

Level 1 – Quoted prices for identical instruments in active markets.

 

   

Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations in which all significant inputs and significant value drivers are observable in active markets.

 

   

Level 3 – Model derived valuations in which one or more significant inputs or significant value drivers are unobservable.

The effective date was for fiscal years beginning after Nov. 15, 2007. In November of 2007, the FASB informally granted a one year deferral for non-financial assets and liabilities. In February 2008, the FASB issued FSP 157-2 which formally delayed the effective date of FAS 157 to fiscal years beginning after Nov. 15, 2008. This FSP is applicable to non-financial assets and non-financial liabilities except for items that are required to be recognized or disclosed at fair value at least annually in the company’s financial statements. As a result, the company adopted FAS 157 effective Jan. 1, 2008 for financial assets and liabilities. See Note 13, Fair Value Measurements.

Additionally, the FASB issued FSP 157-1 in February 2008 to exclude FAS 13, Accounting for Leases, and related pronouncements addressing lease fair value measurements from the scope of FAS 157. Assets and liabilities assumed in a business combination are not covered under this scope exception. The effective date of this FSP coincides with the adoption of FAS 157.

The company will continue to evaluate FAS 157 for the remaining non-financial assets and liabilities to be included effective Jan. 1, 2009. The company does not believe applying FAS 157 to the remaining non-financial assets and liabilities will be material to its results of operations, statement of position or cash flows.

3. Regulatory

Cost Recovery – Tampa Electric Company and PGS

Tampa Electric Company and PGS recover the cost of fuel, purchased power, eligible environmental expenditures, and conservation through cost recovery clauses that are adjusted on an annual basis. As part of the regulatory process, it is reasonably likely that third parties may intervene in various matters related to fuel, purchased power, environmental and conservation cost recovery.

 

10


SO2 Emission Allowances

The Clean Air Act Amendments of 1990 (Clean Air Act) established SO2 allowances to manage the achievement of SO2 emissions requirements. The legislation also established a market-based SO2 allowance trading component.

An allowance authorizes a utility to emit one ton of SO2 during a given year. The Environmental Protection Agency (EPA) allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use in current or future years. In addition, the EPA withholds a small percentage of the annual SO2 allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause. These gains are reflected in “Revenues-Regulated electric and gas” on the Consolidated Condensed Statements of Income.

Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO2 allowances unneeded and sold resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.

During the three months ended Mar. 31, 2008, approximately 2,500 allowances were sold resulting in proceeds of $1.0 million. No allowances were sold during the three months ended Mar. 31, 2007.

Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the Federal Energy Regulatory Commission (FERC).

Tampa Electric and PGS apply the accounting treatment permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71). Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year. Details of the regulatory assets and liabilities as of Mar. 31, 2008 and Dec. 31, 2007 are presented in the following table:

 

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Regulatory Assets and Liabilities

 

(millions)

   Mar. 31,
2008
   Dec. 31,
2007

Regulatory assets:

     

Regulatory tax asset (1)

   $ 64.9    $ 62.5
             

Other:

     

Cost recovery clauses

     35.7      47.2

Postretirement benefit asset

     96.1      97.5

Deferred bond refinancing costs (2)

     24.5      25.5

Environmental remediation

     11.3      11.4

Competitive rate adjustment

     4.9      5.4

Other

     4.6      4.7
             

Total other regulatory assets

     177.1      191.7
             

Total regulatory assets

     242.0      254.2

Less: Current portion

     55.3      67.4
             

Long-term regulatory assets

   $ 186.7    $ 186.8
             

Regulatory liabilities:

     

Regulatory tax liability (1)

   $ 18.5    $ 18.8
             

Other:

     

Deferred allowance auction credits

     0.1      0.1

Cost recovery clauses

     92.0      18.9

Environmental remediation

     11.4      11.4

Transmission and delivery storm reserve

     21.3      20.3

Deferred gain on property sales (3)

     4.2      4.7

Accumulated reserve-cost of removal

     544.8      543.5

Other

     1.4      0.4
             

Total other regulatory liabilities

     675.2      599.3
             

Total regulatory liabilities

     693.7      618.1

Less: Current portion

     102.9      35.4
             

Long-term regulatory liabilities

   $ 590.8    $ 582.7
             

 

(1) Related to plant life and derivative positions.
(2) Amortized over the term of the related debt instrument.
(3) Amortized over a 5-year period with various ending dates.

All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods:

Regulatory assets

 

     Mar. 31,    Dec. 31,

(millions)

   2008    2007

Clause recoverable (1)

   $ 40.5    $ 52.6

Earning a rate of return (2)

     100.4      101.7

Regulatory tax assets (3)

     64.9      62.5

Capital structure and other (3)

     36.2      37.4
             

Total

   $ 242.0    $ 254.2
             

 

(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar for dollar basis in the next year.
(2) Primarily reflects allowed working capital, which is included in rate base and earns an 8.2% rate of return as permitted by the FPSC.
(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

 

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4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax returns for the years 2005 and 2006 during 2007. The U.S. federal statute of limitations remains open for the year 2007 and onward. Year 2007 is currently under examination by the IRS under the Compliance Assurance Program, a program in which the company is a participant. The company does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits for the 2007 tax year. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2002 and onward.

The company recognizes interest and penalties associated with uncertain tax positions in the Consolidated Condensed Statements of Income. During the three month periods ended Mar. 31, 2008 and Mar. 31, 2007, the company recorded approximately $0.2 million of pre-tax charges for interest only in each of those periods. No amounts have been recorded for penalties for the three month periods ended Mar. 31, 2008 and Mar. 31, 2007.

During the three month periods ended Mar. 31, 2008 and Mar. 31, 2007, the company experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included permanent reinvestment of foreign income under Accounting Principles Board Opinion No. 23, Accounting for Taxes – Special Areas, depletion, repatriation of foreign source income to the United States, and reduction of income tax expense under the new “tonnage tax” regime.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. The obligations of the Supplemental Executive Retirement Plan (SERP) were remeasured as of Jan. 1, 2008 to reflect the impact on this benefit plan of the settlement of the SERP obligations related to the retirement of certain participants. Settlement costs of $0.9 million that reflect the accelerated recognition of previously deferred actuarial gains were reclassed from accumulated other comprehensive income. These costs were recognized in the quarter ended Mar. 31, 2008 and are included in “Operation other expense - Other” in the Consolidated Condensed Statements of Income. Other than the remeasurement of plan obligations for these participant retirements and, as discussed in Amendment No. 1 to the company’s Annual Report on Form 10-K for the year ended Dec. 31, 2007, the impacts of the termination of TECO Transport employees’ participation in these plans as a result of the sale of TECO Transport in December 2007, no significant changes have been made to these benefit plans since Dec. 31, 2003.

Pension Expense

 

(millions)    Pension Benefits     Other Postretirement Benefits

Three months ended Mar. 31,

   2008     2007     2008    2007

Components of net periodic benefit expense

         

Service cost

   $ 3.9     $ 4.0     $ 1.0    $ 1.3

Interest cost on projected benefit obligations

     8.0       8.2       3.0      3.0

Expected return on assets

     (9.8 )     (9.1 )     —        —  

Amortization of:

         

Transition obligation

     —         —         0.6      0.7

Prior service (benefit) cost

     (0.1 )     (0.1 )     0.4      0.7

Actuarial loss

     1.0       2.3       —        —  
                             

Pension expense

     3.0       5.3       5.0      5.7

Settlement cost

     0.9       —         —        —  
                             

Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income

   $ 3.9     $ 5.3     $ 5.0    $ 5.7
                             

For the fiscal 2008 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.90% for pension benefits under its qualified pension plan as of its Dec. 4, 2007 remeasurement date; a discount rate of 5.90% for its SERP benefits as of its Jan. 1, 2008 remeasurement date; and a discount rate of 6.20% for other postretirement benefits at its Sep. 30, 2007 measurement date. As a result of the Dec. 4, 2007 and Jan. 1, 2008 remeasurements, benefit obligations for the pension plans increased $18.5 million.

Effective Dec. 31, 2006, in accordance with FAS 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, TECO Energy adjusted its postretirement benefit obligations and recorded other comprehensive income (loss) to reflect the unamortized transition obligation, prior service cost, and actuarial gains and losses of its postretirement

 

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benefit plans. The adjustment to other comprehensive income was net of amounts that, for regulatory purposes prescribed by FAS 71, were recorded as regulatory assets for Tampa Electric Company. For the three months ended Mar. 31, 2008, TECO Energy and its subsidiaries reclassed $0.5 million of unamortized transition obligation, prior service cost and actuarial gains and losses from accumulated other comprehensive income to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2008, Tampa Electric Company reclassed $1.4 million of unamortized transition obligation, prior service cost and actuarial gains and losses from regulatory assets to net income as part of periodic benefit expense.

6. Short-Term Debt

At Mar. 31, 2008 and Dec. 31, 2007, the following credit facilities and related borrowings existed:

Credit Facilities

 

     Mar. 31, 2008    Dec. 31, 2007

(millions)

   Credit
Facilities
   Borrowings
Outstanding (1)
   Letters
of Credit
Outstanding
   Credit
Facilities
   Borrowings
Outstanding (1)
   Letters
of Credit
Outstanding

Tampa Electric Company:

                 

5-year facility

   $ 325.0    $ —      $ 1.4    $ 325.0    $ —      $ —  

1-year accounts receivable facility

     150.0      18.0      —        150.0      25.0      —  

TECO Energy/TECO Finance:

                 

5-year facility (2)

     200.0      —        9.5      200.0      —        9.5
                                         

Total

   $ 675.0    $ 18.0    $ 10.9    $ 675.0    $ 25.0    $ 9.5
                                         

 

(1) Borrowings outstanding are reported as notes payable.
(2) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

These credit facilities require commitment fees ranging from 9.0 to 17.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2008 and Dec. 31, 2007 was 2.83% and 4.76% respectively.

7. Long-Term Debt

Remarketing and Repurchase in Lieu of Redemption of Tampa Electric Company’s Tax-Exempt Auction Rate Bonds

On Mar. 19, 2008, the Hillsborough County Industrial Development Authority (HCIDA) remarketed $86.0 million Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006, in a fixed-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The bonds, which previously had been in auction rate mode, bear interest at 5.00% per annum and are subject to mandatory tender for purchase on Mar. 15, 2012 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the bonds. Regularly scheduled principal and interest when due is insured by Ambac Assurance Corporation, as more fully described in our 2007 Annual Report on Form 10-K.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $75.0 million Polk County Industrial Development Authority (PCIDA) Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 and $125.8 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C (the “2007 Bonds”). Also on that date, the Insurance Agreement dated as of Jul. 27, 2007 with Financial Guaranty Insurance Company, pursuant to which Financial Guaranty Insurance Company issued a financial guaranty insurance policy for the HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C bonds (the “2007 HCIDA Bonds”), was terminated. The company also entered into a corresponding First Supplemental Loan and Trust Agreement regarding the removal of the bond insurance on the 2007 HCIDA Bonds. After these changes to the 2007 HCIDA Bonds, the company remarketed the $54.2 million Series A and the $51.6 million Series B 2007 bonds in long term interest rate modes. The $54.2 million Series A bonds, which previously had been in auction rate mode, bear interest at 5.65% per annum until maturity on Mar. 15, 2018. The $51.6 million Series B bonds, which previously had been in auction rate mode, bear interest at 5.15% per annum and will be subject to mandatory tender on Sep. 1, 2013 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the 2007 Bonds.

As a result of these transactions, $95.0 million of the bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Mar. 31, 2008 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

 

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8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income for the three months ended Mar. 31, 2008 and 2007, related to changes in the fair value of cash flow hedges, amortization of unrecognized benefit costs associated with the company’s pension plans and unrecognized gains and losses on available-for-sale securities:

 

Other Comprehensive Income    Three months ended Mar. 31,  

(millions)

   Gross     Tax     Net  

2008

      

Unrealized (loss) gain on cash flow hedges

   $ (9.6 )   $ 3.7     $ (5.9 )

Amortization of unrecognized benefit costs

     0.4       (0.1 )     0.3  

Change in benefit obligations due to remeasurement

     (17.6 )     6.8       (10.8 )

Unrealized loss on available-for-sale securities (1)

     (1.0 )     —         (1.0 )
                        

Total other comprehensive (loss) income

   $ (27.8 )   $ 10.4     $ (17.4 )
                        

2007

      

Unrealized gain on cash flow hedges

   $ 2.7     $ (1.0 )   $ 1.7  

Add: Loss reclassified to net income

     0.3       (0.1 )     0.2  
                        

Gain on cash flow hedges

     3.0       (1.1 )     1.9  

Amortization of unrecognized benefit costs

     1.1       (0.7 )     0.4  
                        

Total other comprehensive income

   $ 4.1     $ (1.8 )   $ 2.3  
                        

Accumulated Other Comprehensive Income (Loss)

(millions)

   Mar. 31, 2008     Dec. 31, 2007  

Unrecognized pension losses and prior service costs (2)

   $ (24.1 )   $ (13.3 )

Unrecognized other benefit losses, prior service costs and transition obligations (3)

     2.6       2.3  

Net unrealized losses from cash flow hedges (4)

     (12.1 )     (6.2 )

Net unrecognized loss on available for sale securities

     (1.0 )     —    
                

Total accumulated other comprehensive loss

   $ (34.6 )   $ (17.2 )
                

 

(1) Amount relates to an off-shore investment not subject to U.S. Federal income tax.
(2) Net of tax benefit of $14.9 million and $8.3 million as of Mar. 31, 2008 and Dec. 31, 2007, respectively.
(3) Net of tax expense of $1.5 million and $1.5 million as of Mar. 31, 2008 and Dec. 31, 2007, respectively.
(4) Net of tax benefit of $7.4 million and $3.8 million as of Mar. 31, 2008 and Dec. 31, 2007, respectively.

9. Earnings Per Share

For the three months ended Mar. 31, 2008 and 2007, stock options of 6.6 million and 6.1 million shares, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect.

 

Earnings Per Share    Three months ended Mar. 31,  

(millions, except per share amounts)

   2008     2007  

Numerator

    

Net income, basic and diluted

   $ 30.8     $ 72.8  
                

Denominator

    

Average number of shares outstanding – basic

     209.7       208.6  

Plus: Incremental shares for assumed conversions:

    

Stock options and contingent performance shares

     3.1       4.1  

Less: Treasury shares which could be purchased

     (2.2 )     (3.1 )
                

Average number of shares outstanding – diluted

     210.6       209.6  
                

Earnings per share

    

Basic

   $ 0.15     $ 0.35  

Diluted

   $ 0.15     $ 0.35  
                

 

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10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with SFAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2008, Tampa Electric Company has estimated its ultimate financial liability to be approximately $11.5 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors, or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves and changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Mar. 31, 2008 is as follows:

 

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Letters of Credit and Guarantees

 

(millions)

Letters of Credit and Guarantees for the Benefit of:

   2008    2009-2012    After(1)
2012
   Total    Liabilities Recognized
at Mar. 31, 2008

Tampa Electric

              

Letters of credit

   $ —      $ —      $ 0.3    $ 0.3    $ —  

Guarantees: Fuel purchase/energy management (2)

     —        —        20.0      20.0      1.7
                                  
     —        —        20.3      20.3      1.7
                                  

TECO Coal

              

Letters of credit

     —        —        6.7      6.7      —  

Guarantees: Fuel purchase related (2)

     —        —        1.4      1.4      1.2
                                  
     —        —        8.1      8.1      1.2
                                  

Other subsidiaries

              

Guarantees: Fuel purchase/energy management (2)

     53.3      —        3.9      57.2      —  
                                  

Unaffiliated parties

              

Letters of credit (3)

     2.5      —        —        2.5      —  
                                  

Total

   $ 55.8    $ —      $ 32.3    $ 88.1    $ 2.9
                                  

 

(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2012.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Mar. 31, 2008. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.
(3) TECO Transport was sold effective Dec. 4, 2007. These letters of credit were replaced by the purchaser in 2008 pursuant to the terms of the sale, and will be cancelled by the issuing bank upon receipt of authorization from the beneficiary.

Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2008, TECO Energy, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets, as required by SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. All significant intercompany transactions are eliminated in the consolidated condensed financial statements of TECO Energy, but are included in determining reportable segments.

 

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Segment Information (1)

 

(millions)    Tampa    Peoples    TECO    TECO (2)    TECO(3)     Other &     TECO

Three months ended Mar. 31,

   Electric    Gas    Coal    Guatemala    Transport     Eliminations     Energy

2008

                  

Revenues—external

   $ 461.2    $ 179.0    $ 149.1    $ 2.3    $ —       $ 0.1     $ 791.7

Sales to affiliates

     0.3      —        —           —         (0.3 )     —  
                                                  

Total revenues

     461.5      179.0      149.1      2.3      —         (0.2 )     791.7

Equity earnings of unconsolidated affiliates

     —        —        —        17.4      —         —         17.4

Depreciation

     45.2      10.3      9.2      0.2      —         0.1       65.0

Total interest charges(1)

     29.4      4.2      2.5      3.8      —         17.8       57.7

Internally allocated interest (1)

     —        —        2.3      3.8      —         (6.1 )     —  

Provision (benefit) for taxes

     8.5      6.4      1.9      1.9      —         (5.6 )     13.1

Net income (loss) from continuing operations

   $ 15.9    $ 10.0    $ 7.5    $ 10.5    $ —       $ (13.1 )   $ 30.8
                                                  

2007

                  

Revenues—external

   $ 471.4    $ 169.2    $ 127.5    $ 1.9    $ 51.3     $ —       $ 821.3

Sales to affiliates

     0.5      —        —        —        24.0       (24.5 )     —  
                                                  

Total revenues

     471.9      169.2      127.5      1.9      75.3       (24.5 )     821.3

Equity earnings of unconsolidated affiliates

     —        —        —        16.1      0.1       —         16.2

Depreciation

     46.4      9.8      9.5      0.2      5.6       0.1       71.6

Total interest charges(1)

     26.8      4.1      2.8      3.8      1.4       28.2       67.1

Internally allocated interest (1)

     —        —        2.6      3.7      (0.2 )     (6.1 )     —  

Provision (benefit) for taxes

     11.0      6.9      20.0      1.3      1.5       (8.9 )     31.8

Net income (loss) from continuing operations

   $ 21.8    $ 11.0    $ 42.4    $ 10.3    $ 6.4     $ (19.1 )   $ 72.8
                                                  

At Mar. 31, 2008

                  

Goodwill

   $ —      $ —      $ —      $ 59.4    $ —       $ —       $ 59.4

Investment in unconsolidated affiliates

     —        —        —        246.0      —         —         246.0

Other non-current investments

     —        —        —        14.0      —         8.0       22.0

Total assets

   $ 4,958.8    $ 796.5    $ 359.6    $ 416.8    $ —       $ 210.7     $ 6,742.4
                                                  

At Dec. 31, 2007

                  

Goodwill

   $ —      $ —      $ —      $ 59.4    $ —       $ —       $ 59.4

Investment in

                     —  

unconsolidated affiliates

     —        —        —        275.5      —         —         275.5

Other non-current investments

     —        —        —        15.0      —         8.0       23.0

Total assets

   $ 4,838.3    $ 761.4    $ 501.2    $ 435.3    $ —       $ 229.0     $ 6,765.2
                                                  

 

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2008 and 2007 were at a pretax rate of 7.25% and 7.5%, respectively, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.
(2) Revenues are exclusive of entities deconsolidated as a result of FIN 46R. Total revenues for unconsolidated affiliates, attributable to TECO Guatemala based on ownership percentages, were $29.9 million and $29.3 million for the three months ended Mar. 31, 2008 and 2007, respectively.
(3) TECO Transport was sold effective Dec. 4, 2007.

12. Derivatives and Hedging

At Mar. 31, 2008, TECO Energy and its affiliates had total derivative assets and liabilities (current and non-current) of $80.6 million and $16.4 million, respectively, compared to total derivative assets and liabilities (current and non-current) of $2.2 million and $26.1 million, respectively, at Dec. 31, 2007. At Mar. 31, 2008 and Dec. 31, 2007, accumulated other comprehensive income (AOCI) included after-tax losses of $12.1 million and $6.2 million, respectively, representing the fair

 

18


value of cash flow hedges of transactions that will occur in the future. Amounts recorded in AOCI reflect the estimated fair value of derivative instruments designated as hedges, based on market prices as of the balance sheet date. These amounts are expected to fluctuate with movements in market prices and may or may not be realized as a loss upon future reclassification from AOCI.

For the three months ended Mar. 31, 2007, TECO Energy and its affiliates reclassified amounts from AOCI and recognized net pretax losses of $0.3 million. No amounts were reclassed for the same period in 2008. (See Note 8, Other Comprehensive Income.) Amounts reclassified from AOCI in 2007 were primarily related to cash flow hedges of physical purchases of fuel oil. For these types of hedge relationships, the loss on the derivative reclassified from AOCI to earnings is offset by the decreased expense arising from higher prices paid for spot purchases of fuel oil. Conversely, reclassification of a gain from AOCI to earnings is offset by the increased cost of spot purchases of fuel oil.

The company expects to reclass pretax losses of $2.8 million from AOCI to the Consolidated Condensed Statements of Income within the next twelve months. However, these losses and other future reclassifications from AOCI will fluctuate with movements in the underlying market price of the derivative instruments. These losses are primarily related to interest rate swaps. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2010.

As a result of applying the provisions of FAS 71, the changes in value of natural gas derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the risks of hedging activities (see Note 3, Regulatory). Based on the fair value of cash flow hedges at Mar. 31, 2008, net pretax gains of $72.2 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next twelve months.

For the three months ended Mar. 31, 2007, the company recognized a pretax gain of $18.8 million relating to crude oil options that were not designated as either a cash flow or fair value hedge.

13. Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. It also requires recognition of trade-date gains related to certain derivative transactions whose fair value has been determined using unobservable market inputs. This guidance supersedes the guidance in Emerging Issues Task Force Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 02-3), which prohibited the recognition of trade-date gains for such derivative transactions when determining the fair value of instruments not traded in an active market.

On Nov. 14, 2007, the FASB reaffirmed its position that companies will be required to implement the standard for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. The FASB did, however, provide a one year deferral for the implementation of FAS 157 for other non-financial assets and liabilities. Effective Jan. 1, 2008, the company adopted FAS 157 for financial assets and liabilities that are carried at fair value on a recurring basis.

FAS 157 is applied prospectively as of the first interim period for the fiscal year in which it is initially adopted, except for limited retrospective adoption for the following three items:

 

   

The valuation of financial instruments using blockage factors;

 

   

Financial instruments that were measured at fair value using the transaction price (as indicated in EITF Issue 02-3); and,

 

   

The valuation of hybrid financial instruments that were measured at fair value using the transaction price (as indicated in FAS 155).

The impact of adoption in these areas would be applied as a cumulative-effect adjustment to opening retained earnings, measured as the difference between the carrying amounts and the fair values of relevant assets and liabilities at the date of adoption. TECO Energy does not have any of the three aforementioned items, and therefore no transition adjustment was recorded.

 

19


Fair Value Hierarchy

FAS 157 specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. In accordance with FAS 157, these two types of inputs have created the following fair value hierarchy:

 

   

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

 

   

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as OTC forwards, options and repurchase agreements.

 

   

Level 3 – Pricing inputs include significant inputs that are generally not observable in the marketplace. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the company performs an analysis of all instruments subject to FAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

This hierarchy requires the use of observable market data when available.

Determination of Fair Value

The company measures fair value using the procedures set forth below for all assets and liabilities measured at fair value that were previously carried at fair value pursuant to other accounting guidelines.

When available, the company uses quoted market prices on assets and liabilities traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the assets and liabilities are traded in a secondary market, the company makes use of acceptable practical expedients to calculate fair value, and classifies such items as Level 2.

If observable transactions and other market data are not available, fair value is based upon internally developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using internally generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

Valuation Techniques

FAS 157 describes three main approaches to measuring the fair value of assets and liabilities:

1) Market Approach —The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business). The market approach includes the use of matrix pricing.

2) Income Approach —The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

3) Cost Approach —The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

 

20


Items Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2008. As required by FAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and interest rate swaps, the market approach was used in determining fair value. For other investments, the income approach was used.

 

Recurring Derivative Fair Value Measures    At fair value as of Mar. 31, 2008

(in millions)

   Level 1    Level 2    Level 3    Total

Assets

           

Natural gas swaps

   $ —      $ 80.6    $ —      $ 80.6

Other investments

     —        —        14.0      14.0
                           

Total

   $ —      $ 80.6    $ 14.0    $ 94.6
                           

Liabilities

           

Natural gas swaps

   $ —      $ 0.1    $ —      $ 0.1

Interest rate swaps

     —        —        16.3      16.3
                           

Total

   $ —      $ 0.1    $ 16.3    $ 16.4
                           

Natural gas and interest rate swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the New York Mercantile Exchange (NYMEX) quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value. The primary pricing inputs in determining the fair value of interest rate swaps are LIBOR swap rates as reported by Bloomberg. For each instrument, the projected forward swap rate is used to determine the stream of cash flows over the tenor of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. An additional $3.2 million liability, primarily in interest rate swaps, is held on the books of unconsolidated affiliates of TECO Guatemala, but is reflected in “Investment in unconsolidated affiliates” on the TECO Energy, Inc. Consolidated Balance Sheets.

Other investments reflect two auction rate securities with a combined par value of $15.0 million. As a result of market conditions, TECO Guatemala changed the valuation technique for these securities to an income approach using a discounted cash flow model. Accordingly, these securities changed to Level 3 within FAS 157’s three tier fair value hierarchy since initial valuation at Jan. 1, 2008.

Based on the fair value determined from the discounted cash flow analysis a temporary impairment was recorded in other comprehensive income. These investments are highly rated and significantly backed by a pool of student loans. Therefore, it is expected that the investments will not be settled at a price less than par value. Because the company has the ability and intent to hold this investment until a recovery of its original investment value, it considers the investment to be temporarily impaired at Mar. 31, 2008.

Assets Measured at Fair Value on a Recurring Basis Using Unobservable Inputs (Level 3)

 

(in millions)

   Auction Rate
Securities
   Interest Rate
Swaps
    Total  

Balance at Jan. 1, 2008

   $ —      $ (9.0 )   $ (9.0 )

Transfers to Level 3

     14.0      —         14.0  

Change in fair market value

     —        (7.3 )     (7.3 )

Included in earnings

     —        —         —    
                       

Balance Mar. 31, 2008

   $ 14.0    $ (16.3 )   $ (2.3 )
                       

 

21


14. Mergers, Acquisitions and Dispositions

Sale of TECO Transport

On Dec. 4, 2007, TECO Diversified, Inc., a wholly-owned subsidiary of the company, sold its entire interest in TECO Transport Corporation for cash to an unaffiliated investment group. In accordance with the provisions of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets (FAS 144), as a result of its significant continuing involvement with Tampa Electric Company related to the waterborne transportation of solid fuel, the results of TECO Transport were reflected in continuing operations for the three months ended Mar. 31, 2007.

Tampa Electric paid United Maritime Group, formerly TECO Transport Corporation, $19.1 million and $24.0 million for the waterborne transportation services described above for the three month periods ended Mar. 31, 2008 and 2007, respectively.

 

22


TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company as of Mar. 31, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Mar. 31, 2008 and 2007. The results of operations for the three months ended Mar. 31, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008. References should be made to the explanatory notes affecting the consolidated financial statements contained in Amendment No. 1 to Tampa Electric Company’s Annual Report on Form 10-K for the year ended Dec. 31, 2007 and to the notes on pages 28 to 37 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

     Page No.

Consolidated Condensed Balance Sheets, Mar. 31, 2008 and Dec. 31, 2007

   24-25

Consolidated Condensed Statements of Income and Comprehensive Income for the three month periods ended Mar. 31, 2008 and 2007

   26

Consolidated Condensed Statements of Cash Flows for the three month periods ended Mar. 31, 2008 and 2007

   27

Notes to Consolidated Condensed Financial Statements

   28-37

 

23


TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

Assets    Mar. 31,     Dec. 31,  

(millions)

   2008     2007  

Property, plant and equipment

    

Utility plant in service

    

Electric

   $ 5,243.7     $ 5,262.0  

Gas

     925.4       917.4  

Construction work in progress

     425.9       363.6  
                

Property, plant and equipment, at original costs

     6,595.0       6,543.0  

Accumulated depreciation

     (1,798.0 )     (1,808.6 )
                
     4,797.0       4,734.4  

Other property

     4.4       4.5  
                

Total property, plant and equipment (net)

     4,801.4       4,738.9  
                

Current assets

    

Cash and cash equivalents

     7.9       11.9  

Receivables, less allowance for uncollectibles of $1.6 and $1.4 at Mar. 31, 2008 and Dec. 31, 2007, respectively

     249.8       238.8  

Inventories, at average cost

    

Fuel

     60.8       66.2  

Materials and supplies

     57.7       58.0  

Current regulatory assets

     55.3       67.4  

Current derivative assets

     72.2       0.3  

Current deferred income taxes

     5.1       —    

Taxes receivable

     —         2.9  

Prepayments and other current assets

     12.1       11.6  
                

Total current assets

     520.9       457.1  
                

Deferred debits

    

Unamortized debt expense

     22.9       22.9  

Long-term regulatory assets

     186.7       186.8  

Long-term derivative assets

     8.4       1.9  

Other

     10.9       11.7  
                

Total deferred debits

     228.9       223.3  
                

Total assets

   $ 5,551.2     $ 5,419.3  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

24


TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets – continued

Unaudited

 

Liabilities and Capital

(millions)

   Mar. 31,
2008
    Dec. 31,
2007
 

Capital

    

Common stock

   $ 1,660.4     $ 1,510.4  

Accumulated other comprehensive loss

     (10.0 )     (5.0 )

Retained earnings

     277.2       295.6  
                

Total capital

     1,927.6       1,801.0  

Long-term debt, less amount due within one year

     1,749.9       1,844.8  
                

Total capitalization

     3,677.5       3,645.8  
                

Current liabilities

    

Long-term debt due within one year

     5.7       5.7  

Notes payable

     18.0       25.0  

Accounts payable

     234.5       237.6  

Customer deposits

     141.1       138.1  

Current regulatory liabilities

     102.9       35.4  

Current derivative liabilities

     16.3       26.0  

Current deferred income taxes

     —         0.3  

Interest accrued

     35.9       23.5  

Taxes accrued

     28.7       16.8  

Other

     11.3       11.3  
                

Total current liabilities

     594.4       519.7  
                

Deferred credits

    

Non-current deferred income taxes

     423.1       407.5  

Investment tax credits

     11.4       12.0  

Long-term derivative liabilities

     0.1       0.1  

Long-term regulatory liabilities

     590.8       582.7  

Other

     253.9       251.5  
                

Total deferred credits

     1,279.3       1,253.8  
                

Total liabilities and capital

   $ 5,551.2     $ 5,419.3  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

25


TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

     Three months ended Mar. 31,  

(millions, except per share amounts)

   2008     2007  

Revenues

    

Electric (includes franchise fees and gross receipts taxes of $18.9 in 2008 and $19.4 in 2007)

   $ 461.4     $ 471.9  

Gas (includes franchise fees and gross receipts taxes of $7.5 in 2008 and $7.6 in 2007)

     179.0       169.0  
                

Total revenues

     640.4       640.9  
                

Expenses

    

Operations

    

Fuel

     163.6       213.1  

Purchased power

     81.9       53.6  

Cost of natural gas sold

     119.0       107.7  

Other

     71.2       57.4  

Maintenance

     34.1       30.5  

Depreciation

     55.5       56.2  

Taxes, federal and state

     14.6       17.6  

Taxes, other than income

     43.6       45.3  
                

Total expenses

     583.5       581.4  
                

Income from operations

     56.9       59.5  
                

Other income

    

Allowance for other funds used during construction

     1.3       1.7  

Taxes, non-utility federal and state

     (0.3 )     (0.3 )

Other income, net

     1.5       2.8  
                

Total other income

     2.5       4.2  
                

Interest charges

    

Interest on long-term debt

     31.4       28.0  

Other interest

     2.6       3.6  

Allowance for borrowed funds used during construction

     (0.5 )     (0.7 )
                

Total interest charges

     33.5       30.9  
                

Net income

   $ 25.9     $ 32.8  
                

Other comprehensive loss, net of tax

    

Net unrealized losses on cash flow hedges

     (5.0 )     —    
                

Other comprehensive loss, net of tax

     (5.0 )     —    
                

Comprehensive Income

   $ 20.9     $ 32.8  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

26


TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

     Three months ended Mar. 31,  

(millions)

   2008     2007  

Cash flows from operating activities

    

Net income

   $ 25.9     $ 32.8  

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

    

Depreciation

     55.5       56.2  

Deferred income taxes

     10.7       (13.4 )

Investment tax credits, net

     (0.6 )     (0.6 )

Allowance for funds used during construction

     (1.3 )     (1.7 )

Deferred recovery clause

     (11.4 )     12.8  

Receivables, less allowance for uncollectibles

     (10.9 )     2.9  

Inventories

     5.7       (18.3 )

Prepayments

     (0.6 )     (0.1 )

Taxes accrued

     14.8       59.7  

Interest accrued

     12.5       6.8  

Accounts payable

     4.1       2.7  

Gain on sale of business/assets

     (0.1 )     (0.2 )

Other

     11.4       12.9  
                

Cash flows from operating activities

     115.7       152.5  
                

Cash flows from investing activities

    

Capital expenditures

     (123.7 )     (118.1 )

Allowance for funds used during construction

     1.3       1.7  
                

Cash flows used in investing activities

     (122.4 )     (116.4 )
                

Cash flows from financing activities

    

Proceeds from long-term debt

     190.8       —    

Common stock

     150.0       —    

Repayment of long-term debt/Purchase in lieu of redemption

     (286.8 )     —    

Net (decrease) increase in short-term debt

     (7.0 )     3.0  

Dividends

     (44.3 )     (37.8 )
                

Cash flows from (used in) financing activities

     2.7       (34.8 )
                

Net increase in cash and cash equivalents

     (4.0 )     1.3  

Cash and cash equivalents at beginning of period

     11.9       5.1  
                

Cash and cash equivalents at end of period

   $ 7.9     $ 6.4  
                

The accompanying notes are an integral part of the consolidated condensed financial statements

 

27


TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies are as follows:

Principles of Consolidation and Basis of Presentation

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS). All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company and subsidiaries as of Mar. 31, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Mar. 31, 2008 and 2007. The results of operations for the three month periods ended Mar. 31, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates. The year end condensed balance sheet data was derived from audited financial statements, however this quarterly report on Form 10-Q does not include all year end disclosures required for an annual report on Form 10-K by GAAP in the United States of America.

Revenues

As of Mar. 31, 2008 and Dec. 31, 2007, unbilled revenues of $46.5 million and $46.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Purchased Power

Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $81.9 million and $53.6 million for the three months ended Mar. 31, 2008 and 2007, respectively. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities (Tampa Electric and PGS) are allowed to recover from customers certain costs incurred through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. These amounts totaled $26.4 million and $27.0 million, respectively, for the three months ended Mar. 31, 2008 and 2007. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These totaled $26.2 million and $26.9 million, respectively, for the three months ended Mar. 31, 2008 and 2007, respectively.

2. New Accounting Pronouncements

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 161, Disclosures about Derivative Instruments and Hedging Activities (FAS 161). FAS 161 was issued to enhance the disclosure framework in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). FAS 161 requires enhanced disclosures about the purpose of an entity’s derivative instruments, how derivative instruments and hedged items are accounted for, and how the entity’s financial position, cash flows, and performance are enhanced by the derivative instruments and hedged items. The guidance in FAS 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. The company does not believe FAS 161 will be material to its results of operations, statement of position or cash flows.

Accounting for Transfers of Financial Assets and Repurchase Financing Transactions

In February 2008, the FASB issued FASB Staff Position (FSP) No. 140-3, Accounting for Transfers of Financial Assets and Repurchase Financing Transactions (FSP 140-3). FSP 140-3 provides guidance when a company enters an agreement (or linked agreements) to transfer a financial asset and establish a repurchase financing. FSP 140-3 prohibits separately accounting for the initial transfer and the repurchase financing unless certain criteria are met. The guidance in FSP 140-3 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. The company does not believe FSP 140-3 will be material to its results of operations, statement of position or cash flows.

 

28


Statement 133 Implementation Issue E23

In January 2008, the FASB cleared Implementation Issue Hedging – General: Issues Involving the Application of the Shortcut Method under Paragraph 68 (Issue E23). Issue E23 amends FAS 133, paragraph 68 to include hedged items with trade dates differing from their settlement dates due to generally established conventions in the marketplace. This allows companies to assume these commitments have no ineffectiveness in a hedging relationship, thus allowing use of the shortcut method for accounting purposes assuming all other conditions within the paragraph are met.

Issue E23 also allows use of the shortcut method if the fair value of an interest rate swap is not zero at inception of the hedge as long as the swap was entered into at the relationship’s inception, there was no transaction price of the swap in the company’s principal or most advantageous market, and the difference between the swap’s fair value and transaction price is due to differing prices within the bid-ask spread between the entry transaction and a hypothetical exit transaction.

The effective date for Issue E23 is for hedging relationships entered into on or after Jan. 1, 2008. The company does not believe Issue E23 will be material to its results of operations, statement of position or cash flows.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (FAS 160). FAS 160 was issued to improve the relevance, comparability and transparency of the financial information provided by requiring: ownership interests be presented in the consolidated statement of financial position separate from parent equity; the amount of net income attributable to the parent and the noncontrolling interest be identified and presented on the face of the consolidated statement of income; changes in the parent’s ownership interest be accounted for consistently; when deconsolidating, that any retained equity interest be measured at fair value; and that sufficient disclosures identify and distinguish between the interests of the parent and noncontrolling owners. The guidance in FAS 160 is effective for fiscal years beginning on or after Dec. 15, 2008. The company is currently assessing the impact of FAS 160, but does not believe it will be material to its results of operations, statement of position or cash flows.

Business Combinations (Revised)

In December 2007, the FASB issued SFAS No. 141R, Business Combinations (FAS 141R). FAS 141R was issued to improve the relevance, representational faithfulness, and comparability of information disclosed in financial statements about business combinations. The Statement establishes principles and requirements for how the acquirer: 1) recognizes and measures the assets acquired, liabilities assumed and any non-controlling interest in the acquiree; 2) recognizes and measures the goodwill acquired; and 3) determines what information to disclose for users of financial statements to evaluate the effects of the business combination. The guidance in FAS 141R is effective prospectively for any business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after Dec. 15, 2008. The company will assess the impact of FAS 141R in the event it enters into a business combination whose expected acquisition date is subsequent to the required adoption date.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FASB Staff Position (FSP) FIN 39-1. This FSP amends FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts by allowing an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The guidance in this FSP is effective for fiscal years beginning after Nov. 15, 2007. The company adopted this FSP effective Jan. 1, 2008 and as of Mar. 31, 2008 did not hold or give collateral.

Fair Value Option For Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of FAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. FAS 159 is effective for fiscal years beginning after Nov. 15, 2007. The company adopted FAS 159 effective Jan. 1, 2008, but did not elect to measure any financial instruments at fair value. Accordingly, its adoption did not have any effect on its results of operations, statement of position or cash flows.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

 

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FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value, and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. SFAS 157 defines the following fair value hierarchy, based on these two types of inputs:

 

   

Level 1 – Quoted prices for identical instruments in active markets.

 

   

Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations in which all significant inputs and significant value drivers are observable in active markets.

 

   

Level 3 – Model derived valuations in which one or more significant inputs or significant value drivers are unobservable.

The effective date was for fiscal years beginning after Nov. 15, 2007. In November of 2007, the FASB informally granted a one year deferral for non-financial assets and liabilities. In February 2008, the FASB issued FSP 157-2 which formally delayed the effective date of FAS 157 to fiscal years beginning after Nov. 15, 2008. This FSP is applicable to non-financial assets and non-financial liabilities except for items that are required to be recognized or disclosed at fair value at least annually in the company’s financial statements. As a result, the company adopted FAS 157 effective Jan. 1, 2008 for financial assets and liabilities. See Note 12, Fair Value Measurements.

Additionally, the FASB issued FSP 157-1 in February 2008 to exclude FAS 13, Accounting for Leases, and related pronouncements addressing lease fair value measurements from the scope of FAS 157. Assets and liabilities assumed in a business combination are not covered under this scope exception. The effective date of this FSP coincides with the adoption of FAS 157.

The company will continue to evaluate FAS 157 for the remaining non-financial assets and liabilities to be included effective Jan. 1, 2009. The company does not believe applying FAS 157 to the remaining non-financial assets and liabilities will be material to its results of operations, statement of position or cash flows.

3. Regulatory

Cost Recovery – Tampa Electric Company and PGS

Tampa Electric Company and PGS recover the cost of fuel, purchased power, eligible environmental expenditures, and conservation through cost recovery clauses that are adjusted on an annual basis. As part of the regulatory process, it is reasonably likely that third parties may intervene in various matters related to fuel, purchased power, environmental and conservation cost recovery.

SO2 Emission Allowances

The Clean Air Act Amendments of 1990 (Clean Air Act) established SO2 allowances to manage the achievement of SO2 emissions requirements. The legislation also established a market-based SO2 allowance trading component.

An allowance authorizes a utility to emit one ton of SO2 during a given year. The Environmental Protection Agency (EPA) allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use in current or future years. In addition, the EPA withholds a small percentage of the annual SO2 allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause. These gains are reflected in “Revenues-Regulated electric and gas” on the Consolidated Condensed Statements of Income.

Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO2 allowances unneeded and sold resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.

During the three months ended Mar. 31, 2008, approximately 2,500 allowances were sold resulting in proceeds of $1.0 million. No allowances were sold during the three months ended Mar. 31, 2007.

Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the Federal Energy Regulatory Commission (FERC).

Tampa Electric and PGS apply the accounting treatment permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71). Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or

 

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decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year. Details of the regulatory assets and liabilities as of Mar. 31, 2008 and Dec. 31, 2007 are presented in the following table:

Regulatory Assets and Liabilities

 

(millions)

   Mar. 31,
2008
   Dec. 31,
2007

Regulatory assets:

     

Regulatory tax asset (1)

   $ 64.9    $ 62.5

Other:

     

Cost recovery clauses

     35.7      47.2

Postretirement benefit asset

     96.1      97.5

Deferred bond refinancing costs (2)

     24.5      25.5

Environmental remediation

     11.3      11.4

Competitive rate adjustment

     4.9      5.4

Other

     4.6      4.7
             

Total other regulatory assets

     177.1      191.7
             

Total regulatory assets

     242.0      254.2

Less: Current portion

     55.3      67.4
             

Long-term regulatory assets

   $ 186.7    $ 186.8
             

Regulatory liabilities:

     

Regulatory tax liability (1)

   $ 18.5    $ 18.8
             

Other:

     

Deferred allowance auction credits

     0.1      0.1

Cost recovery clauses

     92.0      18.9

Environmental remediation

     11.4      11.4

Transmission and delivery storm reserve

     21.3      20.3

Deferred gain on property sales (3)

     4.2      4.7

Accumulated reserve-cost of removal

     544.8      543.5

Other

     1.4      0.4
             

Total other regulatory liabilities

     675.2      599.3
             

Total regulatory liabilities

     693.7      618.1

Less: Current portion

     102.9      35.4
             

Long-term regulatory liabilities

   $ 590.8    $ 582.7
             

 

(1) Related to plant life and derivative positions.
(2) Amortized over the term of the related debt instrument.
(3) Amortized over a 5-year period with various ending dates.

All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods:

Regulatory assets

 

(millions)

   Mar. 31,
2008
   Dec. 31,
2007

Clause recoverable (1)

   $ 40.5    $ 52.6

Earning a rate of return (2)

     100.4      101.7

Regulatory tax assets (3)

     64.9      62.5

Capital structure and other (3)

     36.2      37.4
             

Total

   $ 242.0    $ 254.2
             

 

(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar for dollar basis in the next year.
(2) Primarily reflects allowed working capital, which is included in rate base and earns an 8.2% rate of return as permitted by the FPSC.

 

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(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

4. Income Taxes

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Tampa Electric Company’s effective tax rates for the three months ended Mar. 31, 2008 and 2007 differ from the statutory rate principally due to state income taxes, amortization of investment tax credits and the domestic activity production deduction.

The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax returns for the years 2005 and 2006 during 2007. The U.S. federal statute of limitations remains open for the year 2007 and onward. Year 2007 is currently under examination by the IRS under the Compliance Assurance Program, a program in which TECO Energy is a participant. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits for the 2007 tax year. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2004 and onward.

The company does not currently have any uncertain tax positions and does not anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease by the end of 2008.

5. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Effective Jan. 1, 2004, Tampa Electric Company adopted FAS 132R (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB Statements No. 87, 88 and 106, with no material effect. No significant changes have been made to these benefit plans since Dec. 31, 2003.

Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. Tampa Electric Company’s portion of the net pension expense for the three months ended Mar. 31, 2008 and 2007, respectively, was $2.1 million and $3.5 million for pension benefits, and $3.5 million and $3.6 million for other postretirement benefits.

Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2008, Tampa Electric Company reclassed $1.4 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

For the fiscal 2008 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.90% for pension benefits under its qualified pension plan as of its Dec. 4, 2007 remeasurement date; a discount rate of 5.90% for its SERP benefits as of its Jan. 1, 2008 remeasurement date; and a discount rate of 6.20% for other postretirement benefits at its Sep. 30, 2007 measurement date. As a result of the Dec. 4, 2007 and Jan. 1, 2008 remeasurements, total benefit obligations for the pension plans increased $18.5 million.

6. Short-Term Debt

At Mar. 31, 2008 and Dec. 31, 2007, the following credit facilities and related borrowings existed:

Credit Facilities

 

     Mar. 31, 2008    Dec. 31, 2007

(millions)

   Credit
Facilities
   Borrowings
Outstanding (1)
   Letters
of Credit
Outstanding
   Credit
Facilities
   Borrowings
Outstanding (1)
   Letters
of Credit
Outstanding

Tampa Electric Company:

                 

5-year facility

   $ 325.0    $ —      $ 1.4    $ 325.0    $ —      $ —  

1-year accounts receivable facility

     150.0      18.0      —        150.0      25.0      —  
                                         

Total

   $ 475.0    $ 18.0    $ 1.4    $ 475.0    $ 25.0    $ —  
                                         

 

(1) Borrowings outstanding are reported as notes payable.

 

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These credit facilities require commitment fees ranging from 9.0 to 17.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2008 and Dec. 31, 2007 was 2.83% and 4.76%, respectively.

7. Long-Term Debt

Remarketing and Repurchase in Lieu of Redemption of Tampa Electric Company’s Tax-Exempt Auction Rate Bonds

On Mar. 19, 2008, the Hillsborough County Industrial Development Authority (HCIDA) remarketed $86.0 million Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006, in a fixed-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The bonds, which previously had been in auction rate mode, bear interest at 5.00% per annum and are subject to mandatory tender for purchase on Mar. 15, 2012 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the bonds. Regularly scheduled principal and interest when due is insured by Ambac Assurance Corporation, as more fully described in our 2007 Annual Report on Form 10-K.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $75.0 million Polk County Industrial Development Authority (PCIDA) Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 and $125.8 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C (the “2007 Bonds”). Also on that date, the Insurance Agreement dated as of Jul. 27, 2007 with Financial Guaranty Insurance Company, pursuant to which Financial Guaranty Insurance Company issued a financial guaranty insurance policy for the HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C bonds (the “2007 HCIDA Bonds”), was terminated. The company also entered into a corresponding First Supplemental Loan and Trust Agreement regarding the removal of the bond insurance on the 2007 HCIDA Bonds. After these changes to the 2007 HCIDA Bonds, the company remarketed the $54.2 million Series A and the $51.6 million Series B 2007 bonds in long term interest rate modes. The $54.2 million Series A bonds, which previously had been in auction rate mode, bear interest at 5.65% per annum until maturity on Mar. 15, 2018. The $51.6 million Series B bonds, which previously had been in auction rate mode, bear interest at 5.15% per annum and will be subject to mandatory tender on Sep. 1, 2013 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the 2007 Bonds.

As a result of these transactions, $95.0 million of the bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Mar. 31, 2008 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

8. Commitments and Contingencies

Legal Contingencies

From time to time Tampa Electric Company and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2008, Tampa Electric Company has estimated its ultimate financial liability to be approximately $11.5 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors, or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves and changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

 

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Guarantees and Letters of Credit

At Mar. 31, 2008, Tampa Electric Company was not obligated under guarantees or letters of credit for the benefit of third parties, including entities under common control. At Mar. 31, 2008, TECO Energy had provided a fuel purchase guarantee on behalf of Tampa Electric Company and had outstanding letters of credit on behalf of Tampa Electric Company in the face amount of $20.0 million and $0.3 million, respectively.

Financial Covenants

In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2008, Tampa Electric Company was in compliance with applicable financial covenants.

9. Related Parties

In October 2003, Tampa Electric signed a five-year contract renewal with a then affiliated company, TECO Transport, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008. TECO Transport was sold to an unaffiliated third-party on Dec. 4, 2007. For the three months ended Mar. 31, 2008, Tampa Electric paid United Maritime Group, formerly TECO Transport and now an unrelated entity, $19.1 million. For the three months ended Mar. 31, 2007, Tampa Electric paid TECO Transport $24.0 million.

10. Segment Information

 

(millions)

Three months ended Mar. 31,

   Tampa
Electric
   Peoples
Gas
   Other &
Eliminations
    Tampa Electric
Company
2008           

Revenues - external

   $ 461.2    $ 179.0    $ —       $ 640.2

Sales to affiliates

     0.3      —        (0.1 )     0.2
                            

Total revenues

     461.5      179.0      (0.1 )     640.4

Depreciation

     45.2      10.3      —         55.5

Total interest charges

     29.4      4.2      (0.1 )     33.5

Provision for taxes

     8.5      6.4      —         14.9

Net income

   $ 15.9    $ 10.0    $ —       $ 25.9
                            

Total assets at Mar. 31, 2008

   $ 4,774.6    $ 786.3    $ (9.7 )   $ 5,551.2
                            
2007           

Revenues - external

   $ 471.4    $ 169.2    $ (0.2 )   $ 640.4

Sales to affiliates

     0.5      —        —         0.5
                            

Total revenues

     471.9      169.2      (0.2 )     640.9

Depreciation

     46.4      9.8      —         56.2

Total interest charges

     26.8      4.1      —         30.9

Provision (benefit) for taxes

     11.0      6.9      (0.3 )     17.6

Net income

   $ 21.8    $ 11.0    $ —       $ 32.8
                            

Total assets at Dec. 31, 2007

   $ 4,672.5    $ 754.3    $ (7.5 )   $ 5,419.3
                            

11. Derivatives and Hedging

At Mar. 31, 2008 and Dec. 31, 2007, Tampa Electric Company and its affiliates had derivative assets (current and non-current) totaling $80.6 million and $2.2 million, respectively, and had derivative liabilities (current and non-current) totaling $16.4 million and $26.1 million, respectively. As a result of applying the provisions of FAS 71, the changes in value of natural gas derivatives are recorded as regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the risks of hedging activities. Included in the derivative liability as of Mar. 31, 2008 is $16.3 million in interest rate swaps related to the forecasted issuance of debt in the second quarter of 2008. These swaps qualify and are accounted for as cash flow hedges and the changes in fair value are recorded in other comprehensive income.

Based on the fair values of derivatives at Mar. 31, 2008, net pretax gains of $72.2 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next twelve months. However, these amounts and other future reclassifications from

 

34


regulatory assets or liabilities and accumulated other comprehensive income will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2010.

12. Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. It also requires recognition of trade-date gains related to certain derivative transactions whose fair value has been determined using unobservable market inputs. This guidance supersedes the guidance in Emerging Issues Task Force Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 02-3), which prohibited the recognition of trade-date gains for such derivative transactions when determining the fair value of instruments not traded in an active market.

On Nov. 14, 2007, the FASB reaffirmed its position that companies will be required to implement the standard for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. The FASB did, however, provide a one year deferral for the implementation of FAS 157 for other non-financial assets and liabilities. Effective Jan. 1, 2008, the company adopted FAS 157 for financial assets and liabilities that are carried at fair value on a recurring basis.

FAS 157 is applied prospectively as of the first interim period for the fiscal year in which it is initially adopted, except for limited retrospective adoption for the following three items:

 

   

The valuation of financial instruments using blockage factors;

 

   

Financial instruments that were measured at fair value using the transaction price (as indicated in EITF Issue 02-3); and,

 

   

The valuation of hybrid financial instruments that were measured at fair value using the transaction price (as indicated in FAS 155).

The impact of adoption in these areas would be applied as a cumulative-effect adjustment to opening retained earnings, measured as the difference between the carrying amounts and the fair values of relevant assets and liabilities at the date of adoption. Tampa Electric Company does not have any of the three aforementioned items, and therefore no transition adjustment was recorded.

Fair Value Hierarchy

FAS 157 specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. In accordance with FAS 157, these two types of inputs have created the following fair value hierarchy:

 

   

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

 

   

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as OTC forwards, options and repurchase agreements.

 

   

Level 3 – Pricing inputs include significant inputs that are generally not observable in the marketplace. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the company performs an analysis of all instruments subject to FAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

 

35


This hierarchy requires the use of observable market data when available.

Determination of Fair Value

The company measures fair value using the procedures set forth below for all assets and liabilities measured at fair value that were previously carried at fair value pursuant to other accounting guidelines.

When available, the company uses quoted market prices on assets and liabilities traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the assets and liabilities are traded in a secondary market, the company makes use of acceptable practical expedients to calculate fair value, and classifies such items as Level 2.

If observable transactions and other market data are not available, fair value is based upon internally developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using internally generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

Valuation Techniques

FAS 157 describes three main approaches to measuring the fair value of assets and liabilities:

1) Market Approach - The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business). The market approach includes the use of matrix pricing.

2) Income Approach - The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

3) Cost Approach -The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Items Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2008. As required by FAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures

 

      At fair value as of Mar. 31, 2008

(in millions)

   Level 1    Level 2    Level 3    Total
Assets            

Natural gas swaps

   $ —      $ 80.6    $ —      $ 80.6
                           

Total

   $ —      $ 80.6    $ —      $ 80.6
                           
Liabilities            

Natural gas swaps

   $ —      $ 0.1    $ —      $ 0.1

Interest rate swaps

     —        —        16.3      16.3
                           

Total

   $ —      $ 0.1    $ 16.3    $ 16.4
                           

Natural gas and interest rate swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the New York Mercantile Exchange (NYMEX) quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value.

The primary pricing inputs in determining the fair value of interest rate swaps are LIBOR swap rates as reported by Bloomberg. For each instrument, the projected forward swap rate is used to determine the stream of cash flows over the tenor of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value.

 

36


Assets Measured at Fair Value on a Recurring Basis Using Unobservable Inputs (Level 3)

 

(in millions)

   Interest Rate
Swaps
 

Balance at Jan. 1, 2008

   $ (9.0 )

Transfers to Level 3

     —    

Change in fair market value

     (7.3 )

Included in earnings

     —    
        

Balance Mar. 31, 2008

   $ (16.3 )
        

 

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Item 2. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Form 10-Q, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; general economic conditions in Tampa Electric’s service area affecting energy sales; economic conditions, both national and international, affecting the demand for TECO Coal’s production; weather variations and changes in customer energy usage patterns affecting sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions or hurricanes; commodity price and operating cost changes affecting the production levels and margins at TECO Coal; the timing of fuel cost recoveries and cash flows at Tampa Electric; natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; and changes in electric tariffs or contract terms affecting TECO Guatemala’s operations. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2007.

Earnings Summary

 

     Three months ended Mar. 31,

(millions, except per share amounts)

   2008    2007

Consolidated revenues

   $ 791.7    $ 821.3
             

Net income from continuing operations

     30.8      72.8
             

Net income

   $ 30.8    $ 72.8
             

Average common shares outstanding

     

Basic

     209.7      208.6

Diluted

     210.6      209.6
             

Earnings per share - basic

     

Earnings per share - basic

   $ 0.15    $ 0.35
             

Earnings per share - diluted

     

Earnings per share - diluted

   $ 0.15    $ 0.35
             

Operating Results

Three Months Ended Mar. 31, 2008:

First quarter net income and net income from continuing operations was $30.8 million or $0.15 per share, compared to $72.8 million, or $0.35 per share, in the first quarter of 2007.

In 2008, first quarter net income included no benefits from the operations of TECO Transport or from the production of synthetic fuel, compared to $6.4 million and $30.7 million, respectively in the 2007 period. First quarter 2008 net income also included a $0.6 million after-tax charge for adjustments to previously estimated costs associated with the sale of TECO Transport, compared to $1.8 million of after-tax charges related to the sale of TECO Transport in 2007.

Tampa Electric Company – Electric division (Tampa Electric)

Net income for the first quarter was $15.9 million, compared with $21.8 million for the same period in 2007. Results for the quarter reflect 0.6% average customer growth and lower retail energy sales. Sales to other utilities were essentially unchanged from 2007. First quarter net income included $1.3 million of Allowance for Funds Used During Construction – Equity (which represents allowed equity cost capitalized to construction costs) related to the construction of nitrogen oxide (NOx) pollution control equipment, compared to $1.7 million included in the 2007 period.

Total retail energy sales decreased 2.1%, driven by lower sales to weather-sensitive residential customers and lower sales to lower-margin phosphate customers due to phosphate production facility outages. Sales to the residential customer segment declined 4.5% in the first quarter due to mild weather patterns and continued lower per residential customer usage. Total degree days in Tampa Electric’s service area were 10% below normal and 11% below the first quarter 2007 period. Base revenues declined $3.2 million in the quarter due to the mild weather. Other operating income increased $4.2 million pretax, driven primarily by higher earnings on the new selective catalytic reduction (SCR) equipment, which is recovered through the environmental cost recovery clause, increased by-product sales, and higher miscellaneous service revenues.

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost recovery clauses, increased $4.5 million after tax, as expected, driven primarily by $1.9 million of after-tax expenditures related to planned outage requirements on power generating equipment. Other factors included $0.4 million of higher after-tax bad debt expense, and higher vehicle fuel costs.

 

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Compared to the first quarter of 2007, depreciation expense decreased $0.7 million after tax, reflecting primarily lower depreciation rates as a result of a depreciation study approved by the FPSC in the third quarter of 2007. Property tax expense decreased $0.3 million after tax compared to the first quarter of 2007, reflecting lower property tax rates from legislation passed in Florida in 2007, as well as adjustments to property valuations previously agreed to with various taxing authorities. Interest expense increased $1.6 million after tax due to higher levels of long-term debt outstanding and higher interest rates on tax-exempt auction-rate debt for one month in the quarter. In addition, interest income decreased due to lower under-recovered fuel balances on which interest is accrued.

A summary of Tampa Electric’s operating statistics for the three months ended Mar. 31, 2008 and 2007 follows:

 

     Operating Revenues     Kilowatt-hour sales  

(millions, except average customers)

   2008     2007     % Change     2008    2007    % Change  

Three months ended Mar. 31,

              

By Customer Type

              

Residential

   $ 207.0     $ 216.3     (4.3 )   1,778.1    1,862.6    (4.5 )

Commercial

     147.5       146.6     0.6     1,468.0    1,458.8    0.6  

Industrial – Phosphate

     16.6       18.8     (11.7 )   244.7    271.4    (9.8 )

Industrial – Other

     27.3       28.7     (4.9 )   305.8    319.7    (4.3 )

Other sales of electricity

     42.6       40.4     5.4     418.6    392.0    6.8  

Deferred and other revenues (1)

     (7.3 )     (3.6 )   (102.8 )   —      —      —    
                                      
     433.7       447.2     (3.0 )   4,215.2    4,304.5    (2.1 )

Sales for resale

     16.0       15.6     2.6     189.1    198.1    (4.5 )

Other operating revenue

     10.8       9.1     18.7     —      —      —    

SO2 Allowance sales

     1.0       —       —       —      —      —    
                                      
   $ 461.5     $ 471.9     (2.2 )   4,404.3    4,502.6    (2.2 )
                                      

Average customers (thousands)

     668.9       664.7     0.6          

Retail output to line (kilowatt hours)

         4,357.7    4,412.3    (1.2 )

 

(1) Primarily reflects the timing of environmental and fuel clause recoveries.

Tampa Electric Company – Natural gas division (PGS)

PGS reported net income of $10.0 million for the first quarter, compared to $11.0 million in the same period in 2007. Quarterly results reflect average customer growth of 0.3% and lower sales to residential customers primarily due to mild winter weather and a continued decline in per residential customer usage. Sales to commercial and industrial customers declined due to the continued weak housing market, which is negatively impacting housing-related industries such as wallboard producers, and the slower economy in general, which is affecting gas usage by commercial customers such as restaurants. Gas transported for power generation customers increased over the first quarter of 2007 when volumes were reduced due to mild weather and the use of other fuels for power generation. Non-fuel operations and maintenance expense decreased primarily due to lower medical claims cost in the quarter partially offset by higher employee-related expenses. Results also reflect higher depreciation expense due to routine plant additions and lower property tax rates reflecting legislation passed in Florida in 2007.

A summary of PGS’ regulated operating statistics for the three months ended Mar. 31, 2008 and 2007 follows:

 

39


Tampa Electric Company – Natural gas division (PGS)

 

      Operating Revenues     Therms  

(millions, except average customers)

   2008    2007    % Change     2008    2007    % Change  

Three months ended Mar. 31,

                

By Customer Type

                

Residential

   $ 48.8    $ 54.3    (10.1 )   27.8    29.2    (4.8 )

Commercial

     44.3      50.2    (11.8 )   107.0    107.5    (0.5 )

Industrial

     2.2      2.5    (12.0 )   46.7    51.4    (9.1 )

Off system sales

     68.6      46.8    46.6     78.6    62.7    25.4  

Power generation

     3.4      2.8    21.4     106.7    65.4    63.1  

Other revenues

     9.8      10.9    (10.1 )   —      —      —    
                                    
   $ 177.1    $ 167.5    5.7     366.8    316.2    16.0  

By Sales Type

                

System supply

   $ 142.7    $ 132.6    7.6     123.9    112.1    10.5  

Transportation

     24.6      24.0    2.5     242.9    204.1    19.0  

Other revenues

     9.8      10.9    (10.1 )         —    
                                    
   $ 177.1    $ 167.5    5.7     366.8    316.2    16.0  
                                    

Average customers (thousands)

     336.1      335.1    0.3          

TECO Coal

TECO Coal achieved first-quarter net income of $7.5 million, compared to $42.4 million in the same period in 2007. Net income in 2008 no longer includes benefits associated with the production of synthetic fuel, which concluded at the end of 2007 concurrent with the expiration of the federal tax credit on the production of synthetic fuel. In 2008, net income included a $0.6 million after-tax benefit reflecting the final adjustment to the 2007 inflation factor applied to the tax credit available on the production of synthetic fuel. In 2007, first quarter results included a $1.6 million after-tax benefit for the final 2006 inflation adjustment to the tax credit. In 2007, net income also included $30.7 million of net benefits related to synthetic fuel production.

Total sales were 2.4 million tons in the 2008 first quarter, compared with 2.1 million tons in the 2007 period, which included 1.3 million tons of synthetic fuel. Sales volumes increased in 2008 in response to the improved market conditions; however, the first quarter sales mix was more heavily weighted to lower margin steam coal due to the timing of metallurgical coal shipments, which largely offset the positive effects of coal sold in the spot market at higher prices. Average net selling prices in 2008, which exclude transportation allowances, were comparable to average net selling prices in the first quarter of 2007 due to the timing of contract signings in 2006 and 2007. In 2008, the cash cost of production per ton was 7% higher than in the first quarter of 2007, driven by higher costs for petroleum related products and explosives.

In 2007, the $30.7 million benefit from the production of synthetic fuel reflected proceeds from the third party investors after an estimated 14% phase out caused by high oil prices, and a $12.3 million after-tax benefit from adjusting to market the valuation of oil price hedges that were placed to protect the 2007 synthetic fuel benefits against high oil prices.

TECO Guatemala

TECO Guatemala reported first-quarter net income of $10.5 million in 2008, compared to $10.3 million in the 2007 period. The 2008 results reflect the benefit of an inflation adjustment to the non-fuel rate for energy sales by the San José Power Station and lower interest expense on the non-recourse financing, higher interest income on higher offshore cash balances, customer growth and higher energy sales at the distribution utility (EEGSA), partially offset by higher operating expenses, and increased earnings from the DECA II affiliated companies.

TECO Guatemala had previously indicated that it was evaluating an opportunity to submit a bid in response to a request for proposal for new coal-fired generating capacity in Guatemala. Due to issues that were raised during the bid process that were not resolved, TECO Guatemala elected to not submit a bid for this project.

Other and Eliminations

The cost for Parent/Other in the first quarter of 2008 was $13.1 million compared to a cost of $19.1 million in the 2007 period. In 2008, net income includes $0.6 million of after-tax adjustment to previously estimated transaction costs related to the sale of TECO Transport, compared to $1.8 million of after-tax transaction-related costs associated with the sale of TECO Transport in 2007.

Results were driven by after-tax interest expense at parent and TECO Finance that was $6.8 million lower in the 2008 period, due to debt redemption and refinancing actions. This was partially offset by $1.9 million after-tax of lower interest income due to lower cash balances.

 

40


TECO Transport

The sale of TECO Transport closed Dec. 4, 2007. Due to the ongoing contractual relationship for solid fuel waterborne transportation services, TECO Transport was not classified as a discontinued operation and is included in TECO Energy’s historical results.

Income Taxes

The provision for income taxes from continuing operations for the three month periods ended Mar. 31, 2008 and Mar. 31, 2007 was an expense of $13.1 million and $31.8 million, respectively. The provision for income taxes from continuing operations in the three months ended Mar. 31, 2008 was impacted by the termination of the synthetic fuel operations tax credit program and its related investor income, as well as by the sale of TECO Transport on Dec. 4, 2007. In addition to the income taxes on recurring operations, the 2007 provision for income taxes includes an income tax benefit related to the application of the “tonnage tax” to qualified vessels.

During the three month periods ended Mar. 31, 2008 and Mar. 31, 2007, the company experienced a number of events that impacted the overall effective tax rate on continuing operations. These events included permanent reinvestment of foreign income under APB No. 23, depletion, repatriation of foreign source income to the United States and reduction of income tax expense under the new “tonnage tax” regime.

Liquidity and Capital Resources

The table below sets forth the Mar. 31, 2008 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and Tampa Electric Company credit facilities.

 

     Balances as of Mar. 31, 2008

(in millions)

   Consolidated    Tampa Electric
Company
   Other    Parent

Credit facilities

   $ 675.0    $ 475.0    $ —      $ 200.0

Drawn amounts / LCs

     28.9      19.4      —        9.5
                           

Available credit facilities

     646.1      455.6      —        190.5

Cash and short term investments

     120.4      7.9      57.4      55.1
                           

Total liquidity

   $ 766.5    $ 463.5    $ 57.4    $ 245.6
                           

Consolidated restricted cash (not included above)

   $ 9.6    $ —      $ 9.6    $ —  

Consolidated other cash and short-term investments includes $7.8 million of cash at the unregulated operating companies for normal operations and $49.6 million of consolidated cash and short-term investments at TECO Guatemala held offshore due to the tax deferral strategy associated with EEGSA. In addition to consolidated cash, as of Mar. 31, 2008, unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash balances of $9.6 million and restricted cash of $0.8 million, which are not included in the table above. The table above also excludes consolidated restricted cash of $7.5 million, primarily at TECO Energy parent.

TECO Energy is targeting $160 million of additional equity contributions to Tampa Electric Company in 2008, above the previously announced plan of $190 million, as the utility enters a period of increased capital spending. In addition, the company expects that it will retire the $100 million of floating rate notes at or near the 2010 maturity date, in lieu of early retirement in 2008.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy/TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. TECO Energy, Tampa Electric Company and the other operating companies are in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Mar. 31, 2008. Reference is made to the specific agreements and instruments for more details.

 

41


Significant Financial Covenants

 

(millions, unless otherwise indicated)

Instrument

  

Financial Covenant (1)

  

Requirement/Restriction

  

Calculation at

Mar. 31, 2008

Tampa Electric Company         
PGS senior notes    EBIT/interest (2)    Minimum of 2.0 times    3.0 times
   Restricted payments    Shareholder equity at least $500    $1,928
   Funded debt/capital    Cannot exceed 65%    48.7%
   Sale of assets    Less than 20% of total assets    0%
Credit facility (3)    Debt/capital    Cannot exceed 65%    47.9%
Accounts receivable credit facility (3)    Debt/capital    Cannot exceed 65%    47.9%
6.25% senior notes    Debt/capital    Cannot exceed 60%    47.9%
   Limit on liens (5)    Cannot exceed $700    $0 liens outstanding
Insurance agreements relating to certain pollution bonds    Limit on liens (5)    Cannot exceed $374 (7.5% of net assets)    $0 liens outstanding
TECO Energy/TECO Finance         
Credit facility (3)    Debt/EBITDA (2)    Cannot exceed 5.0 times    2.8 times
   EBITDA/interest (2)    Minimum of 2.6 times    4.6 times
   Limit on additional indebtedness    Cannot exceed $1,041    $0
   Dividend restriction (4)    Cannot exceed $51 per quarter    $42
TECO Energy 7.5% notes    Limit on liens (5)    Cannot exceed $272 (5% of tangible assets    $0 liens outstanding
TECO Energy floating rate and 6.75% notes and TECO Finance 6.75 notes    Restrictions on secured debt    (6)    (6)
TECO Diversified         
Coal supply agreement guarantee    Dividend restriction    Net worth not less than $379 (40% of tangible net assets)    $731

 

(1) As defined in each applicable instrument.
(2) EBIT generally represents earnings before interest and taxes. EBITDA generally represents EBIT before depreciation and amortization. However, in each circumstance, the term is subject to the definition prescribed under the relevant agreements.
(3) See description of credit facilities in Note 6 to the 2007 TECO Energy, Inc. Annual Report on Form 10-K.
(4) TECO Energy cannot declare quarterly dividends in excess of the restricted amount unless liquidity projections demonstrating sufficient cash or cash equivalents to make each of the next three quarterly dividend payments are delivered to the Administrative Agent.
(5) If the limitation on liens is exceeded, the company is required to provide ratable security to the holders of these notes.
(6) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by Principal Property or Capital Stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes.

 

42


Credit Ratings of Senior Unsecured Debt at Mar. 31, 2008

 

     Standard & Poor’s    Moody’s    Fitch

Tampa Electric Company

   BBB-    Baa2    BBB+

TECO Energy/TECO Finance

   BB+    Baa3    BBB-

In March 2008, Fitch upgraded the ratings on TECO Energy and TECO Finance senior unsecured debt to investment grade at BBB-. In addition, Fitch removed TECO Energy, TECO Finance and Tampa Electric Company from ratings watch positive and placed stable outlooks on the ratings.

Fitch’s ratings upgrade of TECO Energy and TECO Finance reflects the leverage reduction resulting from the use of TECO Transport sale proceeds to reduce debt and from earlier debt reduction efforts. Fitch also cited TECO Energy’s reduced business risk resulting from sales of non-regulated operations and focus on utility operations as factors considered in the upgrade.

Standard & Poor’s, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for Standard & Poor’s is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign Tampa Electric Company’s senior unsecured debt investment grade ratings. The ratings assigned to senior unsecured debt of TECO Energy and TECO Finance by Moody’s and Fitch are investment grade and by Standard & Poor’s are below investment grade.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Any future downgrades in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings.

Off-Balance Sheet Financing

Unconsolidated affiliates have project debt balances as follows at Mar. 31, 2008. TECO Energy has no debt payment obligations with respect to these financings. Although the company is not directly obligated on the debt, the equity interest in those unconsolidated affiliates and our commitments with respect to those projects are at risk if those projects are not operated successfully.

 

(millions)

   Long-term Debt    Ownership Interest  

San José Power Station

   $ 70.0    100 %

Alborada Power Station

   $ 8.7    96 %

DECA II

   $ 217.0    30 %

Outlook

TECO Energy is maintaining its outlook for 2008 earnings per share from continuing operations within a range of $0.95 and $1.10, and expects its results for the year to be driven by essentially the same factors as outlined in February.

First quarter customer growth at the utilities reflects a more significant slowdown in the Tampa area and Florida economies than previously forecast. Due to the high levels of builder inventory homes and other vacancies, Tampa Electric expects full-year customer growth to be only slightly above the first quarter levels. This is a significant reduction from prior Tampa Electric customer growth projections for 2008, and it reflects the impact of the economic and housing market slowdowns in Florida. Assuming the housing market strengthens and the housing inventory is absorbed, Tampa Electric expects the rate of customer growth to increase in 2009, and for customer growth to return to about the 2% level in 2010. The company anticipates that weather-normalized energy sales will grow at levels consistent with customer growth. In response to the slower near-term customer growth, Tampa Electric continues to evaluate the build versus buy option and final timing of generating capacity additions beyond 2010. PGS expects customer growth at about the same level as Tampa Electric, driven by the weak Florida housing market, which is down from previous PGS customer growth projections. PGS expects per residential customer usage to continue to decline due to increased appliance efficiency, price elasticity and more energy efficient housing construction.

TECO Coal now expects to increase 2008 sales to 10.5 million tons in response to improved market conditions. Higher selling prices for the additional sales are expected to offset the effects of higher prices now expected to be paid for diesel fuel and petroleum related products in 2008, resulting in average after-tax margins of about $4 per ton for the year.

Fair Value Measurements

Effective Jan. 1, 2008, the company adopted SFAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about financial assets and liabilities carried at fair value. The majority of the company’s financial assets and liabilities are in the form of natural gas and interest rate derivatives classified as cash flow hedges. The implementation of FAS 157 did not have a material impact on our results of operations, liquidity or capital.

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on

 

43


customers. As a result of applying the provisions of FAS 71, the changes in value of natural gas derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

Interest rate derivatives at the regulated utilities were entered into as a cash flow hedge to lock in a fixed rate on a debt issuance anticipated to occur in the second quarter of 2008. Changes in the value of these instruments are recorded in accumulated other comprehensive income and will be amortized to income over the life of the related debt. The amounts amortized are not expected to be material to the results of operations.

Critical Accounting Policies and Estimates

Our critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of our critical accounting policies, see our Annual Report on Form 10-K for the year ended Dec. 31, 2007.

 

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are exposed to changes in interest rates primarily as a result of our borrowing activities. We may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt.

In March 2008, Tampa Electric Company converted $191.75 million aggregate principal amount of tax-exempt bonds originally issued for its benefit in auction rate mode and remarketed them in long-term interest rate modes. In addition, Tampa Electric purchased in lieu of redemption $95.0 million aggregate value of tax exempt bonds previously in auction rate mode and held such bonds at March 31, 2008, pending a determination of their disposition. The result of these transactions lowered our exposure to variable interest rate risk.

Credit Risk

We are exposed to credit risk as a result of our purchases and sales of energy commodities and related hedging activities. As of Mar. 31, 2008, there was no significant change in our exposure to credit risk since Dec. 31, 2007.

Commodity Risk

We face varying degrees of exposure to commodity risks—including coal, natural gas, fuel oil and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services and do affect the net fair value of derivatives. We assess and monitor risk using a variety of measurement tools based on the degree of exposure of each operating company to commodity risk. Our most significant commodity risk exposure for the remainder of 2008 is the potential effect of high natural gas prices on our cash flows. Prudently incurred costs for natural gas are recoverable through FPSC-approved cost recovery clauses, and therefore do not affect our earnings. However, higher than expected prices for natural gas can affect the timing of recovery and thus impact cash flows.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three months ended Mar. 31, 2008:

 

Changes in Fair Value of Derivatives (millions)

      

Net fair value of derivatives as of Dec. 31, 2007

   $ (23.9 )

Additions and net changes in unrealized fair value of derivatives

     99.2  

Changes in valuation techniques and assumptions

     —    

Realized net settlement of derivatives

     (11.1 )
        

Net fair value of derivatives as of Mar. 31, 2008

   $ 64.2  
        

Roll-Forward of Derivative Net Assets (Liabilities) (millions)

      

Total derivative net liabilities as of Dec. 31, 2007

   $ (23.9 )

Change in fair value of net derivative assets:

  

Recorded as regulatory assets and liabilities or other comprehensive income

     99.2  

Recorded in earnings

     —    

Realized net settlement of derivatives

     (11.1 )

Net option premium payments

     —    

Net purchase (sale) of existing contracts

     —    
        

Net fair value of derivatives as of Mar. 31, 2008

   $ 64.2  
        

 

44


Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Mar. 31, 2008:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Mar. 31, 2008

 

Contracts Maturing in

   Current     Non-current    Total Fair Value  

Source of fair value (millions)

       

Actively quoted prices

   $ 72.1     $ 8.4    $ 80.5  

Other external sources (1)

     (16.3 )     —        (16.3 )

Model prices (2)

     —         —        —    
                       

Total

   $ 55.8     $ 8.4    $ 64.2  
                       

 

(1) Information from external sources includes information obtained from OTC brokers, industry price services or surveys and multiple-party on-line platforms.
(2) Model prices are used for determining the fair value of energy derivatives where price quotes are infrequent or the market is illiquid. Significant inputs to the models are derived from market-observable data and actual historical experience.

For all unrealized derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

 

Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

 

(a) Evaluation of Disclosure Controls and Procedures. TECO Energy’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this quarterly report (the Evaluation Date). Based on such evaluation, TECO Energy’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective.

 

(b) Changes in Internal Controls. There was no change in TECO Energy’s internal control over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TECO Energy’s internal controls that occurred during TECO Energy’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Tampa Electric Company

 

(a) Evaluation of Disclosure Controls and Procedures. Tampa Electric Company’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of Tampa Electric Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the Evaluation Date. Based on such evaluation, Tampa Electric Company’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, Tampa Electric Company’s disclosure controls and procedures are effective.

 

(b) Changes in Internal Controls. There was no change in Tampa Electric Company’s internal control over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of Tampa Electric Company’s internal controls that occurred during Tampa Electric Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

 

45


PART II. OTHER INFORMATION

 

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table shows the number of shares of TECO Energy common stock deemed to have been repurchased by TECO Energy.

 

     (a)
Total Number of
Shares (or Units)
Purchased (1)
   (b)
Average Price Paid
per Share (or Unit)
   (c)
Total Number of Shares (or
Units) Purchased as Part of
Publicly Announced Plans
or Programs
   (d)
Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs

Jan. 1, 2008 – Jan. 31, 2008

   732    $ 16.91    —      —  

Feb. 1, 2008 – Feb. 29, 2008

   12,728    $ 15.44    —      —  

Mar. 1, 2008 – Mar. 31, 2008

   2,850    $ 15.48    —      —  

Total 1st Quarter 2008

   16,310    $ 15.51    —      —  

 

(1) These shares were not repurchased through a publicly announced plan or program, but rather relate to compensation or retirement plans of the company. Specifically, these shares represent shares delivered in satisfaction of the exercise price and/or tax withholding obligations by holders of stock options who exercised options (granted under TECO Energy’s incentive compensation plans), shares delivered or withheld (under the terms of grants under TECO Energy’s incentive compensation plans) to offset tax withholding obligations associated with the vesting of restricted shares and shares purchased by the TECO Energy Group Retirement Savings Plan pursuant to directions from plan participants or dividend reinvestment.

 

Item 6. EXHIBITS

Exhibits - See index on page 48.

 

46


SIGNATURES

Pursuant to the requirements 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.

 

            TECO ENERGY, INC.
      (Registrant)
      By:  

/s/ G. L. GILLETTE

Date:   May 2, 2008       G. L. GILLETTE
       

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

      TAMPA ELECTRIC COMPANY
      (Registrant)
      By:  

/s/ G. L. GILLETTE

Date:   May 2, 2008       G. L. GILLETTE
       

Senior Vice President - Finance and Chief Financial Officer

(Principal Financial Officer)

 

47


INDEX TO EXHIBITS

 

Exhibit No.

  

Description

  3.1 *    Articles of Incorporation of TECO Energy, Inc., as amended on Apr. 20, 1993 (Exhibit 3, Form 10-Q for the quarter ended Mar. 31, 1993 of TECO Energy, Inc.).
  3.2 *    Bylaws of TECO Energy, Inc., as amended effective Jan. 30, 2008 (Exhibit 3.1, Form 8-K dated Jan. 30, 2008 of TECO Energy, Inc.).
  3.3 *    Articles of Incorporation of Tampa Electric Company (Exhibit 3, Registration Statement No. 2-70653 of Tampa Electric Company).
  3.4 *    Bylaws of Tampa Electric Company, as amended effective Jan. 30, 2008 (Exhibit 3.4, Form 10-K for 2007 of TECO Energy, Inc. and Tampa Electric Company).
  4.1 *    First Supplemental Loan and Trust Agreement dated as of Mar. 26, 2008 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1, Form 8-K dated Mar. 26, 2008 of Tampa Electric Company).
12.1    Ratio of Earnings to Fixed Charges – TECO Energy, Inc.
12.2    Ratio of Earnings to Fixed Charges – Tampa Electric Company.
31.1    Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2    Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3    Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4    Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1    Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
32.2    Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)

 

(1) This certification accompanies the Quarterly Report on Form 10-Q and is not filed as part of it.
* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

 

48