Index to Financial Statements

 

 

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, 2010

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

 

 

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 the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).    YES  ¨    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. 30, 2010 was 213,917,701. As of Apr. 30, 2010, 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 54

Index to Exhibits appears on page 53.

 

 

 

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Index to Financial Statements

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, 2010 and Dec. 31, 2009, and the results of their operations and cash flows for the periods ended Mar. 31, 2010 and 2009. The results of operations for the three month period ended Mar. 31, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 and to the notes on pages 8 through 25 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

		Page No.
Consolidated Condensed Balance Sheets, Mar. 31, 2010 and Dec. 31, 2009		3-4
Consolidated Condensed Statements of Income for the three month periods ended Mar. 31, 2010 and 2009		5
Consolidated Condensed Statements of Comprehensive Income for the three month periods ended Mar. 31, 2010 and 2009		6
Consolidated Condensed Statements of Cash Flows for the three month periods ended Mar. 31, 2010 and 2009		7
Notes to Consolidated Condensed Financial Statements		8-25

 

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Index to Financial Statements

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

Assets (millions, except for share amounts)		Mar. 31, 2010				Dec. 31, 2009
Current assets
Cash and cash equivalents		$	232.0			$	46.0
Short-term investments			—				0.8
Receivables, less allowance for uncollectibles of $3.3 and $3.0 at Mar. 31, 2010 and Dec. 31, 2009, respectively			347.9				277.4
Inventories, at average cost
Fuel			154.0				124.3
Materials and supplies			74.5				65.7
Current derivative asset			0.5				0.8
Current regulatory assets			117.0				109.2
Prepayments and other current assets			24.5				25.7
Income tax receivables			2.1				1.7
Total current assets			952.5				651.6
Property, plant and equipment
Utility plant in service
Electric			6,300.2				6,079.5
Gas			1,024.6				1,017.2
Construction work in progress			346.0				304.5
Other property			382.3				377.2
Property, plant and equipment			8,053.1				7,778.4
Accumulated depreciation			(2,318.4	)			(2,234.3	)
Total property, plant and equipment, net			5,734.7				5,544.1
Other assets
Deferred income taxes			188.5				222.7
Long-term regulatory assets			338.2				335.6
Long-term derivative assets			0.3				0.2
Investment in unconsolidated affiliates			146.2				279.3
Goodwill			59.4				59.4
Deferred charges and other assets			131.0				126.6
Total other assets			863.6				1,023.8
Total assets		$	7,550.8			$	7,219.5

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

 

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Index to Financial Statements

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

 

 

Liabilities and Capital (millions, except for share amounts)		Mar. 31, 2010				Dec. 31, 2009
Current liabilities
Long-term debt due within one year
Recourse		$	206.5			$	106.5
Non-recourse			9.8				1.4
Notes payable			18.0				55.0
Accounts payable			240.3				251.4
Customer deposits			153.1				151.2
Current regulatory liabilities			69.0				85.4
Current derivative liabilities			67.8				34.0
Interest accrued			74.9				45.3
Taxes accrued			42.7				20.5
Other current liabilities			17.4				20.6
Total current liabilities			899.5				771.3
Other liabilities
Investment tax credits			10.7				10.8
Long-term regulatory liabilities			608.2				602.6
Long-term derivative liabilities			8.1				3.6
Deferred credits and other liabilities			534.5				544.2
Long-term debt, less amount due within one year
Recourse			3,342.6				3,195.4
Non-recourse			42.2				6.2
Total other liabilities			4,546.3				4,362.8
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 213.9 million shares outstanding at Mar. 31, 2010 and Dec. 31, 2009)			213.9				213.9
Additional paid in capital			1,533.3				1,530.8
Retained earnings			378.8				365.7
Accumulated other comprehensive loss			(21.5	)			(25.0	)
TECO Energy Stockholders' Equity			2,104.5				2,085.4
Noncontrolling Interest			0.5				—
Total Equity			2,105.0				2,085.4
Total liabilities and capital		$	7,550.8			$	7,219.5

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

 

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Index to Financial Statements

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

		Three months ended Mar. 31,
(millions, except per share amounts)		2010				2009
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $30.9 in 2010 and $30.1 in 2009)		$	706.5			$	653.8
Unregulated			205.8				170.2
Total revenues			912.3				824.0
Expenses
Regulated operations
Fuel			164.0				228.7
Purchased power			57.2				42.2
Cost of natural gas sold			116.0				88.3
Other			87.9				77.0
Operation other expense
Mining related costs			117.6				118.5
Guatemalan Power Generation			15.2				3.1
Other			1.6				1.0
Maintenance			44.7				52.4
Depreciation and amortization			77.0				69.7
Restructuring charges			1.5				—
Taxes, other than income			60.7				60.4
Total expenses			743.4				741.3
Income from operations			168.9				82.7
Other income (expense)
Allowance for other funds used during construction			1.0				3.3
Other income			3.4				14.0
Loss on debt extinguishment			(26.4	)			—
Income from equity investments			2.7				8.8
Total other income			(19.3	)			26.1
Interest charges
Interest expense			59.9				57.6
Allowance for borrowed funds used during construction			(0.6	)			(1.3	)
Total interest charges			59.3				56.3
Income before provision for income taxes			90.3				52.5
Provision for income taxes			34.3				17.8
Net income		$	56.0			$	34.7
Less: Net income attributable to noncontrolling interest			(0.2	)			—
Net income attributable to TECO Energy		$	55.8			$	34.7
Average common shares outstanding – Basic			212.2				211.4
– Diluted			213.9				212.2
Earnings per share attributable to TECO Energy – Basic		$	0.26			$	0.16
– Diluted		$	0.26			$	0.16
Dividends paid per common share outstanding		$	0.20			$	0.20

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

 

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Index to Financial Statements

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

 

		Three months ended Mar. 31,
(millions)		2010				2009
Net income		$	56.0			$	34.7
Other comprehensive income (loss), net of tax
Net unrealized gains on cash flow hedges			0.8				2.5
Amortization of unrecognized benefit costs and other			1.8				0.3
Recognized benefit costs due to settlement			0.9				—
Reclassification to earnings - loss on available-for-sale securities			—				1.7
Other comprehensive income, net of tax			3.5				4.5
Comprehensive income		$	59.5			$	39.2
Comprehensive income attributable to noncontrolling interests			(0.2	)			—
Comprehensive income attributable to TECO Energy, Inc.		$	59.3			$	39.2

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

 

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Index to Financial Statements

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

 

		Three months ended Mar. 31,
(millions)		2010				2009
Cash flows from operating activities
Net income		$	56.0			$	34.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			77.0				69.7
Deferred income taxes			36.3				18.1
Investment tax credits, net			(0.1	)			(0.1	)
Allowance for funds used during construction			(1.0	)			(3.3	)
Non-cash stock compensation			1.7				1.8
Gain on sale of business/assets, pretax			(0.4	)			(18.7	)
Non-cash debt extinguishment, pretax			0.9				—
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings			(2.7	)			(7.1	)
Deferred recovery clauses			7.9				66.9
Receivables, less allowance for uncollectibles			(58.4	)			(9.1	)
Inventories			(22.4	)			(27.7	)
Prepayments and other current assets			2.6				5.2
Taxes accrued			19.7				13.1
Interest accrued			26.5				33.6
Accounts payable			6.7				(23.4	)
Other			(8.9	)			25.0
Cash flows from operating activities			141.4				178.7
Cash flows from investing activities
Capital expenditures			(142.9	)			(191.0	)
Allowance for funds used during construction			1.0				3.3
Net proceeds from sale of business/assets			0.4				29.1
Restricted cash			—				0.2
Contributions to unconsolidated affiliates			(0.6	)			—
Other investments			0.8				2.4
Cash flows used in investing activities			(141.3	)			(156.0	)
Cash flows from financing activities
Dividends			(42.7	)			(42.6	)
Proceeds from the sale of common stock			1.1				1.0
Proceeds from long-term debt			543.5				—
Repayment of long-term debt/Purchase in lieu of redemption			(302.4	)			(1.4	)
Dividend to noncontrolling interest			(0.7	)			—
Net (decrease) increase in short-term debt			(37.0	)			43.0
Cash flows from financing activities			161.8				—
Net increase in cash and cash equivalents			161.9				22.7
Cash and cash equivalents at beginning of period (1)			70.1				12.2
Cash and cash equivalents at end of period		$	232.0			$	34.9

 

(1)	In accordance with new accounting guidance, cash and cash equivalents for the three months ended Mar. 31, 2010 have been adjusted to include the $24.1 million from the reconsolidation of two projects in Guatemala effective Jan. 1, 2010. (See Note 16.)

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

 

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Index to Financial Statements

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 (VIEs) for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Effective Jan. 1, 2010, amended accounting standards on consolidation resulted in the reconsolidation of two projects in Guatemala. Prior periods presented in this quarterly report were not restated. (See Note 16.)

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 is 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, 2010 and Dec. 31, 2009, and the results of operations and cash flows for the periods ended Mar. 31, 2010 and 2009. The results of operations for the three month period ended Mar. 31, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010.

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, 2010 and Dec. 31, 2009, unbilled revenues of $57.4 million and $51.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

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 $30.9 million for the three months ended Mar. 31, 2010, compared to $30.1 million for the three months ended Mar. 31, 2009. 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 $30.8 million for the three months ended Mar. 31, 2010, compared to $30.0 million for the three months ended Mar. 31, 2009.

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 $57.2 million for the three months ended Mar. 31, 2010, compared to $42.2 million for the three months ended Mar. 31, 2009. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses.

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 which 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 ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

2. New Accounting Pronouncements

Subsequent Events

In February 2010, the Financial Accounting Standards Board (FASB) issued additional guidance related to subsequent event disclosure. The guidance was effective upon issuance and has no effect on the company’s results of operations, statement of position or cash flows.

 

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Index to Financial Statements

Fair Value Measures and Disclosures

In January 2010, the FASB issued guidance that requires entities to disclose more information regarding the movements between Levels 1 and 2 of the fair value hierarchy. The guidance was effective for fiscal years that begin after Dec. 15, 2010, and for interim periods within that year. This guidance will not have any effect on the company’s results of operations, statement of position or cash flows.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric also is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). However, pursuant to a waiver granted in accordance with the FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually effective May 2009, an increase of $4.0 million from the prior year, to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $31.4 million and $29.3 million as of Mar. 31, 2010 and Dec. 31, 2009, respectively.

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 FERC.

Tampa Electric and PGS apply the accounting standards for regulated operations. 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.

 

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Index to Financial Statements

Details of the regulatory assets and liabilities as of Mar. 31, 2010 and Dec. 31, 2009 are presented in the following table:

Regulatory Assets and Liabilities

 

(millions)		Mar. 31, 2010			Dec. 31, 2009
Regulatory assets:
Regulatory tax asset (1)		$	68.9		$	69.0
Other:
Cost recovery clauses			103.5			89.4
Postretirement benefit asset			226.0			229.1
Deferred bond refinancing costs (2)			17.0			18.0
Environmental remediation			21.4			21.2
Competitive rate adjustment			2.9			3.1
Other			15.5			15.0
Total other regulatory assets			386.3			375.8
Total regulatory assets			455.2			444.8
Less: Current portion			117.0			109.2
Long-term regulatory assets		$	338.2		$	335.6
Regulatory liabilities:
Regulatory tax liability (1)		$	18.6		$	19.6
Other:
Cost recovery clauses			45.1			61.4
Environmental remediation			19.9			19.9
Transmission and delivery storm reserve			31.4			29.3
Deferred gain on property sales (3)			2.2			2.8
Accumulated reserve-cost of removal			559.2			554.3
Other			0.8			0.7
Total other regulatory liabilities			658.6			668.4
Total regulatory liabilities			677.2			688.0
Less: Current portion			69.0			85.4
Long-term regulatory liabilities		$	608.2		$	602.6

 

(1)	Primarily related to plant life and derivative positions.

(2)	Amortized over the term of the related debt instrument.

(3)	Amortized over a 4 or 5-year period with various ending dates.

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

Regulatory assets

 

(millions)		Mar. 31, 2010			Dec 31, 2009
Clause recoverable (1)		$	106.4		$	92.5
Components of rate base (2)			235.4			238.1
Regulatory tax assets (3)			68.9			69.0
Capital structure and other (3)			44.5			45.2
Total		$	455.2		$	444.8

 

(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 a 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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Index to Financial Statements

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 2008 consolidated federal income tax return during 2009. There is one open issue for the 2008 tax return for which an Appeals Conference is expected to take place in June 2010. The U.S. federal statute of limitations remains open for the year 2006 and onward. Years 2009 and 2010 are 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 by the end of 2010. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from 3 to 5 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 2004 and forward. In the first quarter of 2010, the company reached a favorable settlement for certain state items that were under appeal. As a result, the company recorded a $2.4 million after-tax benefit, excluding interest.

The company recognizes interest and penalties associated with uncertain tax positions in the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. During the three month periods ended Mar. 31, 2010 and Mar. 31, 2009, the company recorded ($1.3) million and $0.3 million, respectively, of pre-tax (income) charges for interest only. Pre-tax income for interest of $1.4 million was recorded during the first quarter of 2010 as a result of reaching a favorable settlement for certain state items that were under appeal. No amounts have been recorded for penalties for the three month periods ended Mar. 31, 2010 or Mar. 31, 2009.

The effective tax rate increased to 37.96% for the three months ended Mar. 31, 2010 from 33.95% for the same period in 2009 primarily due to an additional $5.2 million valuation allowance related to our updated, anticipated ability to use foreign tax credits.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company.

Pension Expense

 

(millions)		Pension Benefits								Other Postretirement Benefits
Three months ended Mar. 31,		2010				2009				2010			2009
Components of net periodic benefit expense
Service cost		$	4.2			$	3.9			$	0.8		$	0.8
Interest cost on projected benefit obligations			8.3				8.3				2.9			2.8
Expected return on assets			(9.0	)			(9.5	)			—			—
Amortization of:
Transition obligation			—				—				0.6			0.6
Prior service (benefit) cost			(0.1	)			(0.1	)			0.2			0.2
Actuarial loss			3.0				1.8				—			—
Pension expense			6.4				4.4				4.5			4.4
Settlement cost			1.5				—				—			—
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income		$	7.9			$	4.4			$	4.5		$	4.4

For the fiscal 2010 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.75% for pension benefits under its qualified pension plan, and a discount rate of 5.60% for its other postretirement benefits as of their Jan. 1, 2010 measurement dates. Additionally, TECO Energy assumed a discount rate of 5.75% for its Supplemental Executive Retirement Plan (SERP) benefits as of its Mar. 1 and Jan. 1, 2010 measurement dates.

Effective Dec. 31, 2006, in accordance with the accounting standard for defined benefit plans and other postretirement benefits, 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 benefit plans. The adjustment to other comprehensive income was net of amounts that, for purposes prescribed by accounting standards for regulated operations, were recorded as regulatory assets for Tampa Electric Company. For the three months ended Mar. 31, 2010, TECO Energy and its subsidiaries reclassed $0.6 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, 2010, Tampa Electric Company reclassed $3.1 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

In connection with the restructuring events that occurred in the third quarter of 2009 that changed the senior management structure, TECO Energy recognized a settlement charge of $1.5 million in the first quarter of 2010 for pay-outs from its SERP.

 

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Index to Financial Statements

In March 2010, the Patient Protection and Affordability Care Act and a companion bill, The Health Care and Education Reconciliation Act were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset by $6.4 million and recorded a corresponding charge of $1.1 million and a regulatory tax asset of $5.3 million.

6. Short-Term Debt

At Mar. 31, 2010 and Dec. 31, 2009, the following credit facilities and related borrowings existed:

Credit Facilities

 

		Mar. 31, 2010									Dec. 31, 2009
(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		$	—		$	0.9		$	325.0		$	55.0		$	0.7
1-year accounts receivable facility			150.0			18.0			—			150.0			—			—
TECO Energy/TECO Finance:
5-year facility (2)			200.0			—			6.7			200.0			—			6.9
Total		$	675.0		$	18.0		$	7.6		$	675.0		$	55.0		$	7.6

 

(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 7.0 to 60.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2010 and Dec. 31, 2009 was 0.64% and 0.66%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 19, 2010, Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 8 to the Loan and Servicing Agreement with certain lenders named therein and Citicorp North America, Inc. as Program Agent. The amendment (i) extends the maturity date to Feb. 18, 2011, (ii) provides that TRC will pay program and liquidity fees, which, pursuant to the amendment, will total 100 basis points, (iii) provides that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank offer rate (if available) plus a margin and (iv) makes other technical changes.

7. Long-Term Debt

Issuance of TECO Finance, Inc. 4.00% Notes due 2016 and 5.15% Notes due 2020

On Mar. 15, 2010, TECO Finance, Inc. issued $250 million aggregate principal amount of 4.00% Notes due Mar. 15, 2016 and $300 million aggregate principal amount of 5.15% Notes due Mar. 15, 2020. The 2016 Notes were priced at 99.594% of the principal amount to yield 4.077% to maturity, and the 2020 Notes were priced at 99.552% of the principal amount to yield 5.208% to maturity. TECO Finance is a wholly owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy for its diversified activities. The TECO Finance notes are fully and unconditionally guaranteed by TECO Energy.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $543.5 million. TECO Finance used a portion of these net proceeds to fund the cash purchase of the TECO Energy and TECO Finance notes tendered in March 2010 (see “TECO Energy, Inc. and TECO Finance, Inc. Tender Offers” below) and to fund the redemptions of the TECO Energy Floating Rate Notes due 2010 and 7.20% Notes due 2011 in April 2010 (see Note 17). TECO Finance may redeem some or all of the notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the Indenture), plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

 

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Index to Financial Statements

TECO Energy, Inc. and TECO Finance, Inc. Tender Offers

On Mar. 22, 2010, TECO Energy and TECO Finance completed debt tender offers which resulted in the purchase of approximately $70 million principal amount of TECO Energy notes for cash and approximately $230 million principal amount of TECO Finance notes for cash.

The tender offers resulted in the purchase and retirement of approximately:

 

•

$43.0 million principal amount of TECO Energy 7.2% notes due 2011

 

•

$27.0 million principal amount of TECO Energy 7.0% notes due 2012

 

•

$156.9 million principal amount of TECO Finance 7.2% notes due 2011

 

•

$73.1 million principal amount of TECO Finance 7.0% notes due 2012.

In connection with these debt tender transactions, $25.5 million of premiums and fees were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Condensed Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Condensed Statements of Cash Flows for the quarter ended Mar. 31, 2010. “Loss on debt extinguishment” also includes remaining unamortized debt issue costs of $0.9 million.

Reconsolidation of TCAE and CGESJ

Effective Jan. 1, 2010, new accounting standards for consolidations amended the determination of the primary beneficiaries for variable interest entities. As a result of adopting these standards, TECO Guatemala, Inc., a wholly-owned subsidiary of TECO Energy, was determined to be the primary beneficiary of, and therefore required to consolidate, both the TCAE and CGESJ projects in Guatemala. (See Note 16.) The consolidation resulted in a net $44.4 million increase of non-recourse debt.

 

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Index to Financial Statements

8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (OCI) for the three months ended Mar. 31, 2010 and 2009, 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
2010
Unrealized gain on cash flow hedges		$	0.4			$	(0.3	)		$	0.1
Plus: Loss reclassified to net income			1.2				(0.5	)			0.7
Gain on cash flow hedges			1.6				(0.8	)			0.8
Amortization of unrecognized benefit costs			0.6				1.2				1.8
Recognized benefit costs due to settlement			1.5				(0.6	)			0.9
Total other comprehensive income		$	3.7			$	(0.2	)		$	3.5
2009
Unrealized loss on cash flow hedges		$	(3.1	)		$	1.2			$	(1.9	)
Plus: Loss reclassified to net income			7.0				(2.6	)			4.4
Gain on cash flow hedges			3.9				(1.4	)			2.5
Amortization of unrecognized benefit costs			0.5				(0.2	)			0.3
Reclassification to earnings loss on available-for-sale securities			1.7				—				1.7
Total other comprehensive income		$	6.1			$	(1.6	)		$	4.5

Accumulated Other Comprehensive Loss

 

(millions)		Mar. 31, 2010				Dec. 31, 2009
Unrecognized pension losses and prior service costs(1)		$	(26.6	)		$	(27.8	)
Unrecognized other benefit gains, prior service costs and transition obligations(2)			11.6				10.1
Net unrealized losses from cash flow hedges(3)			(6.5	)			(7.3	)
Total accumulated other comprehensive loss		$	(21.5	)		$	(25.0	)

 

(1)	Net of tax benefit of $16.9 million and $17.1 million as of Mar. 31, 2010 and Dec. 31, 2009, respectively.

(2)	Net of tax expense of $4.6 and $6.0 million as of Mar. 31, 2010 and Dec. 31, 2009, respectively.

(3)	Net of tax benefit of $3.7 million and $4.5 million as of Mar. 31, 2010 and Dec. 31, 2009, respectively.

 

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Index to Financial Statements

9. Earnings Per Share

Earnings Per Share

 

		Three months ended Mar. 31,
(millions, except per share amounts)		2010				2009
Basic earnings per share
Net income from continuing operations		$	56.0			$	34.7
Less: Income attributable to noncontrolling interest			(0.2	)			—
Less: Amount allocated to nonvested participating shareholders			(0.4	)			(0.3	)
Net Income attributable to TECO Energy available to common shareholders - basic		$	55.4			$	34.4
Average shares outstanding common			212.2				211.4
Basic earnings per share attributable to TECO Energy available to common shareholders		$	0.26			$	0.16
Diluted earnings per share
Net income from continuing operations		$	56.0			$	34.7
Less: Income attributable to noncontrolling interest			(0.2	)			—
Less: Amount allocated to nonvested participating shareholders			(0.4	)			(0.3	)
Net income attributable to TECO Energy available to common shareholders - diluted		$	55.4			$	34.4
Average shares outstanding common			212.2				211.4
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net			1.7				0.8
Adjusted average shares outstanding common - diluted			213.9				212.2
Diluted earnings per share attributable to TECO Energy available to common shareholders		$	0.26			$	0.16
Anti-dilutive shares			4.8				7.1

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 accounting standards 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 Tampa Electric and PGS, is a potentially responsible party (PRP) for certain superfund sites and, through PGS, 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, 2010, Tampa Electric Company has estimated its ultimate financial liability to be approximately $19.9 million, primarily at PGS, 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 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 or 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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Index to Financial Statements

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and Tampa Electric Company’s letters of credit and guarantees as of Mar. 31, 2010 is as follows:

Letters of Credit and Guarantees-TECO Energy

 

(millions) Letters of Credit and Guarantees for the Benefit of:		2010			2011-2014			After(1) 2014			Total			Liabilities Recognized at Mar. 31, 2010
Tampa Electric
Guarantees:
Fuel purchase/energy management (2)		$	—		$	—		$	20.0		$	20.0		$	0.4
			—			—			20.0			20.0			0.4
TECO Coal
Letters of credit			—			—			6.7			6.7			—
Guarantees: Fuel purchase related (2)			—			—			1.4			1.4			1.9
			—			—			8.1			8.1			1.9
Other subsidiaries
Guarantees:
Fuel purchase/energy management (2)			—			—			109.7			109.7			—
Total		$	—		$	—		$	137.8		$	137.8		$	2.3
Letters of Credit-Tampa Electric Company
(millions) Letters of Credit for the Benefit of:		2010			2011-2014			After(1) 2014			Total			Liabilities Recognized at Mar. 31, 2010
Tampa Electric
Letters of credit		$	—		$	—		$	0.9		$	0.9		$	—
Total		$	—		$	—		$	0.9		$	0.9		$	—

 

(1)	These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2014.

(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, 2010. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2010, TECO Energy, TECO Finance, 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 the accounting guidance for 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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Index to Financial Statements

Segment Information ⁽¹⁾

 

(millions) Three months ended Mar. 31,		Tampa Electric			Peoples Gas			TECO Coal			TECO (2) Guatemala			Other & Eliminations				TECO Energy
2010
Revenues - external		$	524.8		$	181.7		$	172.0		$	33.8		$	—			$	912.3
Sales to affiliates			0.3			11.2			—			—			(11.5	)			—
Total revenues			525.1			192.9			172.0			33.8			(11.5	)			912.3
Equity earnings of unconsolidated affiliates			—			—			—			3.2			(0.5	)			2.7
Depreciation			53.0			11.4			10.8			1.8			—				77.0
Restructuring charges			—			—			—			—			1.5				1.5
Total interest charges(1)			30.3			4.6			1.8			4.6			18.0				59.3
Internally allocated interest (1)			—			—			1.8			3.3			(5.1	)			—
Provision (benefit) for taxes			27.8			11.2			2.4			4.0			(11.1	)			34.3
Net income (loss) attributable to TECO Energy		$	48.1		$	17.9		$	16.8		$	10.4		$	(37.4	)		$	55.8
2009
Revenues - external		$	507.3		$	146.5		$	168.1		$	2.1		$	—			$	824.0
Sales to affiliates			0.3			6.5			—			—			(6.8	)			—
Total revenues			507.6			153.0			168.1			2.1			(6.8	)			824.0
Equity earnings of unconsolidated affiliates			—			—			—			8.8			—				8.8
Depreciation			48.0			10.8			10.6			0.2			0.1				69.7
Total interest charges(1)			28.2			4.7			1.8			3.2			18.4				56.3
Internally allocated interest (1)			—			—			1.5			3.1			(4.6	)			—
Provision (benefit) for taxes			9.4			7.2			1.3			9.6			(9.7	)			17.8
Net income (loss) attributable to TECO Energy		$	18.3		$	11.2		$	8.0		$	13.2		$	(16.0	)		$	34.7
At Mar. 31, 2010
Goodwill		$	—		$	—		$	—		$	59.4		$	—			$	59.4
Investment in unconsolidated affiliates			—			—			—			145.9			0.3				146.2
Total assets		$	5,782.6		$	904.1		$	348.5		$	428.7		$	86.9			$	7,550.8
At Dec. 31, 2009
Goodwill		$	—		$	—		$	—		$	59.4		$	—			$	59.4
Investment in unconsolidated affiliates			—			—			—			279.2			0.1				279.3
Total assets		$	5,697.9		$	870.1		$	326.6		$	380.7		$	(55.8	)		$	7,219.5

 

(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 2010 and 2009 were at a pretax rate of 7.15% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2)

Revenues for 2009 are exclusive of entities deconsolidated as a result of the accounting guidance for variable interest entities. Total revenues for unconsolidated affiliates, attributable to TECO Guatemala based on ownership percentages, were $18.7 million for the three months ended Mar. 31, 2009. Entities were consolidated as of Jan. 1, 2010 as a result of accounting guidance effective on that date. See Note 16 for more information. 2009 earnings include the sale of a 16.5% interest in the Central American fiber optic telecommunications provider Navega. (See Note 14.)

12. Accounting for Derivative Instruments and Hedging Activities

From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:

 

•

To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS;

 

•

To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates; and

 

•

To limit the exposure to price fluctuations for physical purchases of fuel at TECO Coal.

 

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Index to Financial Statements

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

New accounting standards for disclosures became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. This new standard requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. The new requirements include quantitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. The company adopted this new standard effective Jan. 1, 2009.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities to reflect the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

A company’s physical contracts qualify for the normal purchase/normal sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Mar. 31, 2010, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at Mar. 31, 2010 and Dec. 31, 2009:

Total Derivatives⁽¹⁾

 

(millions)		Mar. 31, 2010			Dec. 31, 2009
Current assets		$	0.5		$	0.8
Long-term assets			0.3			0.2
Total assets		$	0.8		$	1.0
Current liabilities		$	67.8		$	34.0
Long-term liabilities			8.1			3.6
Total liabilities		$	75.9		$	37.6

 

(1)	Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The following table presents the derivative hedges of heating oil contracts at Mar. 31, 2010 and Dec. 31, 2009 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Heating Oil Derivatives

 

(millions)		Mar. 31, 2010			Dec. 31, 2009
Current assets		$	—		$	—
Long-term assets			0.3			0.2
Total assets		$	0.3		$	0.2
Current liabilities		$	0.3		$	0.9
Long-term liabilities			—			—
Total liabilities		$	0.3		$	0.9

 

18

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Index to Financial Statements

The following table presents the derivative hedges of natural gas contracts at Mar. 31, 2010 and Dec. 31, 2009 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives

 

(millions)		Mar. 31, 2010			Dec. 31, 2009
Current assets		$	0.5		$	0.8
Long-term assets			—			—
Total assets		$	0.5		$	0.8
Current liabilities		$	66.6		$	33.1
Long-term liabilities			8.1			3.6
Total liabilities		$	74.7		$	36.7

The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Mar. 31, 2010 is a net loss of $6.5 million after tax and accumulated amortization. This compares to a net loss of $7.3 million in AOCI after tax and accumulated amortization at Dec. 31, 2009.

The following table presents the derivative hedges of interest rate swaps at Mar. 31, 2010 and Dec. 31, 2009 to limit the exposure to market changes in interest rates on outstanding debt:

Interest Rate Swaps

 

(millions)		Mar. 31, 2010			Dec. 31, 2009 (1)
Current assets		$	—		$	—
Long-term assets			—			—
Total assets		$	—		$	—
Current liabilities		$	0.9		$	—
Long-term liabilities			—			—
Total liabilities		$	0.9		$	—

 

(1)	Interest rate swaps residing on the balance sheet of TECO Guatemala, Inc. were deconsolidated at Dec. 31. 2009. See Note 16.

 

19

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Index to Financial Statements

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at Mar. 31, 2010:

Derivatives Designated As Hedging Instruments

 

		Asset Derivatives					Liability Derivatives
(millions) at Mar. 31, 2010		Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value
Commodity Contracts:
Heating oil derivatives:
Current		Derivative assets		$	—		Derivative liabilities		$	0.3
Long-term		Derivative assets			0.3		Derivative liabilities			—
Natural gas derivatives:
Current		Derivative assets			0.5		Derivative liabilities			66.6
Long-term		Derivative assets			—		Derivative liabilities			8.1
Interest rate swaps:
Current		Derivative assets			—		Derivative liabilities			0.9
Long-term		Derivative assets			—		Derivative liabilities			—
Total derivatives designated as hedging instruments				$	0.8				$	75.9

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Mar. 31, 2010:

Energy Related Derivatives

 

(millions) at Mar. 31, 2010		Balance  Sheet Location(1)		Fair Value			Balance  Sheet Location(1)		Fair Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities		$	0.5		Regulatory assets		$	66.6
Long-term		Regulatory liabilities			—		Regulatory assets			8.1
Total				$	0.5				$	74.7

 

(1)

Natural gas derivatives are deferred, in accordance with accounting standards for regulated operations and all increases and decreases in the cost of natural gas supply are passed on to customers with the fuel recovery clause mechanism. As gains and losses are realized in future periods, they will be recorded as fuel costs in the Consolidated Condensed Statements of Income.

Based on the fair value of the instruments at Mar. 31, 2010, net pretax losses of $66.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

 

20

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Index to Financial Statements

The following table presents the effect of hedging instruments on OCI and income for the three months ended Mar. 31:

 

		Amount of Gain/(Loss) on Derivatives Recognized in OCI				Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
(millions)
Derivatives in Cash Flow Hedging Relationships		Effective Portion(1)				Effective Portion(1)
2010
Interest rate contracts:		$	(0.1	)		Interest expense		$	(0.4	)
Commodity contracts:
Heating oil derivatives			0.2			Mining related costs			(0.3	)
Total		$	0.1					$	(0.7	)
2009
Interest rate contracts:		$	—			Interest expense		$	(0.5	)
Commodity contracts:
Heating oil derivatives			(1.4	)		Mining related costs			(3.7	)
Natural gas derivatives			(0.5	)					(0.2	)
Total		$	(1.9	)				$	(4.4	)

 

(1)	Changes in OCI and AOCI are reported in after-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2010 and 2009, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the three months ended Mar. 31:

 

(millions)		Fair Value Asset/(Liability)				Amount of Gain/(Loss) Recognized in OCI(1)				Amount of Gain/(Loss) Reclassified From AOCI Into Income
2010
Interest rate swaps		$	(0.9	)		$	(0.1	)		$	(0.4	)
Heating oil derivatives			—				0.2				(0.3	)
Total		$	(0.9	)		$	0.1			$	(0.7	)
2009
Interest rate swaps		$	—			$	—			$	(0.5	)
Heating oil derivatives			(22.4	)			(1.4	)			(3.7	)
Natural gas derivatives			(172.5	)			(0.5	)			(0.2	)
Total		$	(194.9	)		$	(1.9	)		$	(4.4	)

 

(1)	Changes in OCI and AOCI are reported in after-tax dollars.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2012 for both financial natural gas and financial heating oil fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of Mar. 31, 2010, are expected to settle during the 2010, 2011 and 2012 fiscal years:

 

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Index to Financial Statements

(millions)		Heating Oil  Contracts (Gallons)				Natural Gas  Contracts (MMBTUs)
Year		Physical		Financial		Physical		Financial
2010		—		7.0		—		29.1
2011		—		4.5		—		20.7
2012		—		—		—		2.3
Total		—		11.5		—		52.1

The company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with diesel fuel and natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Mar. 31, 2010, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) Edison Electric Institute agreements (EEI) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

The company has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. The company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of Mar. 31, 2010, substantially all positions with counterparties are net liabilities.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where Tampa Electric Company is the counterparty, Tampa Electric Company’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including Tampa Electric Company’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at Mar 31, 2010:

Contingent Features

 

(millions) At Mar. 31, 2010		Fair Value Asset/ (Liability)				Derivative Exposure Asset/ (Liability)				Posted Collateral
Credit Rating		$	(74.4	)		$	(74.4	)		$	—

13. Fair Value Measurements

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, 2010. As required by accounting standards for fair value measurements, 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, interest rate and heating oil swaps, the market approach was used in determining fair value.

 

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Index to Financial Statements

Recurring Fair Value Measures

 

		At fair value as of Mar. 31, 2010
(millions)		Level 1			Level 2			Level 3			Total
Assets
Natural gas swaps		$	—		$	0.5		$	—		$	0.5
Heating oil swaps			—			0.3			—			0.3
Total		$	—		$	0.8		$	—		$	0.8
Liabilities
Natural gas swaps		$	—		$	74.7		$	—		$	74.7
Interest rate swaps			—			0.9			—			0.9
Heating oil swaps			—			0.3			—			0.3
Total		$	—		$	75.9		$	—		$	75.9
		At fair value as of Dec. 31, 2009
(millions)		Level 1			Level 2			Level 3			Total
Assets
Natural gas swaps		$	—		$	0.8		$	—		$	0.8
Heating oil swaps			—			0.2			—			0.2
Total		$	—		$	1.0		$	—		$	1.0
Liabilities
Natural gas swaps		$	—		$	36.7		$	—		$	36.7
Heating oil swaps			—			0.9			—			0.9
Total		$	—		$	37.6		$	—		$	37.6

Natural gas and heating oil swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of these 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 life of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value.

Fair Value of Debt Outstanding

At Mar. 31, 2010, total long-term debt had a carrying amount of $3,604.01 million and an estimated fair market value of $3,823.0 million. At Dec. 31, 2009, total long-term debt had a carrying amount of $3,309.7 million and an estimated fair market value of $3,500.3 million.

14. Mergers, Acquisitions and Dispositions

Sale of Navega

On Mar. 13, 2009, TECO Guatemala sold its 16.5% interest in the Central American fiber optic telecommunications provider Navega. The sale resulted in a pretax gain of $18.3 million and total proceeds of $29.0 million.

15. Restructuring Charges

On Jul. 30, 2009, TECO Energy, Inc. announced organizational changes and a new senior management structure as part of its response to industry changes, economic uncertainties and its commitment to maintain a lean and efficient organization. As a second step in response to these factors, on Aug. 31, 2009, the company decided on a total reduction in force of 229 jobs. The reduction in force was substantially completed by Dec. 31, 2009. In connection with this reduction in force, the company incurred total costs of $26.6 million related to severance and other benefits. For the three months ended Mar. 31, 2010, the remaining $1.5 million of these costs were recognized on the Consolidated Condensed Statements of Income under “Restructuring Charges”. The company’s wholly-owned subsidiary, Tampa Electric Company, incurred $23.1 million of such costs, all of which were recognized in the year ended Dec. 31, 2009. The total cash payments related to these actions were $28.4 million; including $4.9 million for the settlement of pension obligations. As of Mar. 31, 2010, all restructuring charges were paid or settled.

 

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Index to Financial Statements

Restructuring Charges to be Incurred

 

		Termination of Benefits				Other Costs				Total
Total costs expected to be incurred		$	26.6			$	0.6			$	27.2
Costs incurred in 2009			(25.1	)			(0.6	)			(25.7	)
Current period costs incurred			(1.5	)			—				(1.5	)
Total costs remaining		$	—			$	—			$	—

Accrued Liability for Restructuring Charges

 

		Termination of Benefits				Other Costs				Total
Beginning balance, Jul. 1, 2009		$	—			$	—			$	—
Costs incurred and charged to expense			26.6				0.6				27.2
Costs paid/settled			(22.9	)			(0.6	)			(23.5	)
Non-cash expense			(3.7	)			—				(3.7	)
Ending balance, Mar. 31, 2010		$	—			$	—			$	—

Restructuring Charges by Segment

 

		Tampa Electric				PGS				Other(1)				Total
Total costs expected to be incurred		$	18.4			$	4.7			$	4.1			$	27.2
Costs incurred in 2009			(18.4	)			(4.7	)			(2.6	)			(25.7	)
Current period costs incurred			—				—				(1.5	)			(1.5	)
Total costs remaining		$	—			$	—			$	—			$	—

 

(1)	Restructuring costs incurred at the parent company.

16. Variable Interest Entities

The company formed Tampa Centro Americana de Electricidad (TCAE) to own and construct the Alborada Power Station and the company formed Central Generadora Eléctrica San José (CGESJ) to own and construct the San José Power Station. Both power stations are located in Guatemala and both projects obtained long-term power purchase agreements (PPAs) with Empresa Eléctrica de Guatemala, S.A. (EEGSA), a distribution utility in Guatemala. The terms of the two separate PPAs include EEGSA’s right to the full capacity of the plants for 15 years, U.S. dollar based capacity payments, certain terms for providing fuel, and certain other terms including the right to extend the Alborada and San José contracts. Under prior accounting standards for consolidation, management believed that EEGSA was the primary beneficiary of the variable interests in TCAE and CGESJ due to the terms of the PPAs. Accordingly, both entities were deconsolidated as of Jan. 1, 2004. The TCAE deconsolidation resulted in the initial removal of $25.0 million of debt and $15.1 million of net assets from TECO Energy’s Consolidated Balance Sheet. The CGESJ deconsolidation resulted in the initial removal of $65.5 million of debt and $106.6 million of net assets from TECO Energy’s Consolidated Balance Sheet. The results of operations for the two projects were classified as “Income from equity investments” on TECO Energy’s Consolidated Statements of Income since the date of deconsolidation through Dec. 31, 2009.

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE’s primary beneficiary. Under the amended standard, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. As a result of adopting this amendment, the company reconsolidated both TCAE and CGESJ.

 

24

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Index to Financial Statements

The following table summarizes combined income statement information for the TCAE and CGESJ projects for the three months ended Mar. 31, 2010, which were consolidated, and Mar. 31, 2009, which were not consolidated:

 

As of Mar. 31, 2010
(millions)		TCAE and CGESJ
Revenues		$	32.6
Operating expenses		$	16.4
Project level income (1)		$	13.5
As of Mar. 31, 2009
Revenues		$	18.7
Operating expenses		$	10.4
Project level income (1)		$	5.7

 

(1)	Excludes taxes, allocated interest expense and administrative and general expenses. Includes project level interest.

The following table summarizes combined balance sheet information for the TCAE and CGESJ projects for the periods ended Mar. 31, 2010, which were consolidated, and Dec. 31, 2009, which were not consolidated:

 

Summary Results
As of Mar. 31, 2010
(millions)		TCAE and CGESJ
Current assets		$	46.9
Long-term assets and other deferred debits			158.5
Total assets		$	205.4
Current liabilities		$	17.9
Long-term liabilities and other deferred credits			45.9
Equity			141.6
Total liabilities and equity		$	205.4
As of Dec. 31, 2009
(millions)		TCAE and CGESJ
Current assets		$	58.1
Long-term assets and other deferred debits			161.2
Total assets		$	219.3
Current liabilities		$	17.6
Long-term liabilities and other deferred credits			51.2
Equity			150.5
Total liabilities and equity		$	219.3

Tampa Electric Company has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interest entities. These risks include: operating and maintenance; regulatory; credit; commodity/fuel; and energy market risk. In most instances, Tampa Electric Company has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric Company is not required to consolidate any of these entities. Tampa Electric Company purchased $57.2 million and $42.2 million under these PPAs for the three months ended Mar. 31, 2010 and 2009, respectively.

In one instance the company’s agreement with the entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under the standards, the company is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, the company is unable to determine if this entity is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. The company has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for the company is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. The company purchased $12.7 million and $6.2 million under this PPA for the three months ended Mar. 31, 2010 and 2009, respectively.

The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. Other than the Guatemalan projects previously mentioned, in the normal course of business, our involvement with the remaining VIEs does not affect our Consolidated Balance Sheets, Statements of Income or Cash Flows.

17. Subsequent Events

Redemption of TECO Energy, Inc. Floating Rate Notes due 2010

On Apr. 14, 2010, TECO Energy redeemed all of the outstanding $100 million aggregate principal amount of its Floating Rate Notes due 2010. The redemption price was equal to 100% of the principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date.

Redemption of TECO Energy, Inc. 7.2% Notes due 2011

On Apr. 22, 2010, TECO Energy redeemed $100 million aggregate principal amount of its 7.2% Notes due 2011. The redemption price was equal to $1,066.38 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date.

 

25

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Index to Financial Statements

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, 2010 and Dec. 31, 2009, and the results of operations and cash flows for the periods ended Mar. 31, 2010 and 2009. The results of operations for the three months ended Mar. 31, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010. 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, 2009 and to the notes on pages 31-40 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

		Page No.
Consolidated Condensed Balance Sheets, Mar. 31, 2010 and Dec. 31, 2009		27-28
Consolidated Condensed Statements of Income and Comprehensive Income for the three month periods ended Mar. 31, 2010 and 2009		29
Consolidated Condensed Statements of Cash Flows for the three month periods ended Mar. 31, 2010 and 2009		30
Notes to Consolidated Condensed Financial Statements		31-40

 

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Index to Financial Statements

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

Assets (millions)		Mar. 31, 2010				Dec. 31, 2009
Property, plant and equipment
Utility plant in service
Electric		$	6,084.2			$	6,065.9
Gas			1,024.6				1,017.2
Construction work in progress			316.5				303.0
Property, plant and equipment, at original costs			7,425.3				7,386.1
Accumulated depreciation			(1,994.3	)			(1,988.1	)
			5,431.0				5,398.0
Other property			4.4				4.4
Total property, plant and equipment, net			5,435.4				5,402.4
Current assets
Cash and cash equivalents			13.9				5.5
Receivables, less allowance for uncollectibles of $2.0 and $1.6 at Mar. 31, 2010 and Dec. 31, 2009, respectively			263.2				228.6
Inventories, at average cost
Fuel			105.4				85.8
Materials and supplies			56.3				55.8
Current regulatory assets			117.0				109.2
Current derivative assets			0.5				0.8
Taxes receivable			—				16.8
Prepayments and other current assets			10.6				12.0
Total current assets			566.9				514.5
Deferred debits
Unamortized debt expense			19.4				20.1
Long-term regulatory assets			338.2				335.6
Other			0.9				1.2
Total deferred debits			358.5				356.9
Total assets		$	6,360.8			$	6,273.8

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

 

27

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Index to Financial Statements

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets—continued

Unaudited

 

Liabilities and Capital (millions)		Mar. 31, 2010				Dec. 31, 2009
Capital
Common stock		$	1,852.4			$	1,802.4
Accumulated other comprehensive loss			(5.9	)			(6.1	)
Retained earnings			317.3				307.5
Total capital			2,163.8				2,103.8
Long-term debt, less amount due within one year			1,994.4				1,994.4
Total capitalization			4,158.2				4,098.2
Current liabilities
Long-term debt due within one year			3.7				3.7
Notes payable			18.0				55.0
Accounts payable			187.0				206.1
Customer deposits			153.1				151.2
Current regulatory liabilities			69.0				85.4
Current derivative liabilities			66.6				33.1
Current deferred income taxes			11.0				15.9
Interest accrued			42.5				27.7
Taxes accrued			55.9				12.1
Other			11.9				16.5
Total current liabilities			618.7				606.7
Deferred credits
Non-current deferred income taxes			560.3				543.8
Investment tax credits			10.7				10.8
Long-term derivative liabilities			8.1				3.6
Long-term regulatory liabilities			608.2				602.6
Other			396.6				408.1
Total deferred credits			1,583.9				1,568.9
Total liabilities and capital		$	6,360.8			$	6,273.8

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

 

28

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Index to Financial Statements

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

		Three months ended Mar. 31,
(millions)		2010				2009
Revenues
Electric (includes franchise fees and gross receipts taxes of $21.4 in 2010 and $22.1 in 2009)		$	525.0			$	501.0
Gas (includes franchise fees and gross receipts taxes of $9.5 in 2010 and $8.0 in 2009)			181.7				153.0
Total revenues			706.7				654.0
Expenses
Operations
Fuel			164.0				228.7
Purchased power			57.2				42.2
Cost of natural gas sold			116.0				88.3
Other			87.7				76.9
Maintenance			30.0				36.2
Depreciation			64.4				58.8
Taxes, federal and state			38.8				16.5
Taxes, other than income			49.3				48.2
Total expenses			607.4				595.8
Income from operations			99.3				58.2
Other income
Allowance for other funds used during construction			1.0				3.3
Taxes, non-utility federal and state			(0.2	)			(0.1	)
Other income, net			0.8				1.0
Total other income			1.6				4.2
Interest charges
Interest on long-term debt			32.7				31.4
Other interest			2.8				2.8
Allowance for borrowed funds used during construction			(0.6	)			(1.3	)
Total interest charges			34.9				32.9
Net income			66.0				29.5
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) on cash flow hedges			0.2				0.2
Total other comprehensive income (loss), net of tax			0.2				0.2
Comprehensive income		$	66.2			$	29.7

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

 

29

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Index to Financial Statements

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

		Three months ended Mar. 31,
(millions)		2010				2009
Cash flows from operating activities
Net income		$	66.0			$	29.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation			64.4				58.8
Deferred income taxes			10.6				0.5
Investment tax credits, net			(0.1	)			(0.1	)
Allowance for funds used during construction			(1.0	)			(3.3	)
Deferred recovery clause			7.9				66.9
Receivables, less allowance for uncollectibles			(34.6	)			5.3
Inventories			(20.1	)			(16.2	)
Prepayments			1.4				3.6
Taxes accrued			60.6				22.3
Interest accrued			14.8				13.1
Accounts payable			0.8				(32.8	)
Gain on sale of assets, pretax			(0.1	)			(0.2	)
Other			(7.3	)			12.0
Cash flows from operating activities			163.3				159.4
Cash flows from investing activities
Capital expenditures			(112.7	)			(177.8	)
Allowance for funds used during construction			1.0				3.3
Net proceeds from sale of assets			—				0.1
Cash flows used in investing activities			(111.7	)			(174.4	)
Cash flows from financing activities
Proceeds from long-term debt			—				—
Common stock			50.0				—
Repayment of long-term debt			—				—
Net (decrease)/increase in short-term debt			(37.0	)			67.0
Dividends			(56.2	)			(46.3	)
Cash flows (used in) from financing activities			(43.2	)			20.7
Net increase in cash and cash equivalents			8.4				5.7
Cash and cash equivalents at beginning of period			5.5				3.6
Cash and cash equivalents at end of period		$	13.9			$	9.3

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

 

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Index to Financial Statements

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies for Tampa Electric Company include:

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, the Natural Gas division, generally referred to as Peoples Gas System (PGS) and the accounts of variable interest entities (VIEs) for which it is the primary beneficiary. Tampa Electric Company is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. (See Note 12.)

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, 2010 and Dec. 31, 2009, and the results of operations and cash flows for the periods ended Mar. 31, 2010 and 2009. The results of operations for the three month period ended Mar. 31, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010.

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 consolidated 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, 2010 and Dec. 31, 2009, unbilled revenues of $57.4 million and $51.6 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 $57.2 million for the three months ended Mar. 31, 2010, compared to $42.2 million for the three months ended Mar. 31, 2009. 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 $30.9 million for the three months ended Mar. 31, 2010, compared to $30.1 million for the three months ended Mar. 31, 2009. 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 $30.8 million for the three months ended Mar. 31, 2010, compared to $30.0 million for the three months ended Mar. 31, 2009.

Cash Flows Related to Derivatives and Hedging Activities

Tampa Electric Company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

2. New Accounting Pronouncements

Subsequent Events

In February 2010, the Financial Accounting Standards Board (FASB) issued additional guidance related to subsequent event disclosure. The guidance was effective upon issuance and has no effect on the company’s results of operations, statement of position or cash flows.

 

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Fair Value Measures and Disclosures

In January 2010, the FASB issued guidance that requires entities to disclose more information regarding the movements between Levels 1 and 2 of the fair value hierarchy. The guidance was effective for fiscal years that begin after Dec. 15, 2010, and for interim periods within that year. This guidance will not have any effect on the company’s results of operations, statement of position or cash flows.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). However, pursuant to a waiver granted in accordance with the FERC’s regulations, Tampa Electric is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually effective May 2009, an increase of $4.0 million from the prior year, to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $31.4 million and $29.3 million as of Mar. 31, 2010 and Dec. 31, 2009, respectively.

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 FERC.

Tampa Electric and PGS apply the accounting standards for regulated operations. 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.

 

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Details of the regulatory assets and liabilities as of Mar. 31, 2010 and Dec. 31, 2009 are presented in the following table:

Regulatory Assets and Liabilities

 

(millions)		Mar. 31, 2010			Dec. 31, 2009
Regulatory assets:
Regulatory tax asset (1)		$	68.9		$	69.0
Other:
Cost recovery clauses			103.5			89.4
Postretirement benefit asset			226.0			229.1
Deferred bond refinancing costs (2)			17.0			18.0
Environmental remediation			21.4			21.2
Competitive rate adjustment			2.9			3.1
Other			15.5			15.0
Total other regulatory assets			386.3			375.8
Total regulatory assets			455.2			444.8
Less: Current portion			117.0			109.2
Long-term regulatory assets		$	338.2		$	335.6
Regulatory liabilities:
Regulatory tax liability (1)		$	18.6		$	19.6
Other:
Cost recovery clauses			45.1			61.4
Environmental remediation			19.9			19.9
Transmission and delivery storm reserve			31.4			29.3
Deferred gain on property sales (3)			2.2			2.8
Accumulated reserve-cost of removal			559.2			554.3
Other			0.8			0.7
Total other regulatory liabilities			658.6			668.4
Total regulatory liabilities			677.2			688.0
Less: Current portion			69.0			85.4
Long-term regulatory liabilities		$	608.2		$	602.6

 

(1)	Primarily related to plant life and derivative positions.

(2)	Amortized over the term of the related debt instrument.

(3)	Amortized over a 4 or 5-year period with various ending dates.

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

Regulatory assets

 

(millions)		Mar. 31, 2010			Dec 31, 2009
Clause recoverable (1)		$	106.4		$	92.5
Components of rate base (2)			235.4			238.1
Regulatory tax assets (3)			68.9			69.0
Capital structure and other (3)			44.5			45.2
Total		$	455.2		$	444.8

 

(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 a 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

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, 2010 and Mar. 31, 2009 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the equity portion of Allowance for Funds Used During Construction.

The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax return for the year 2008 during 2009. There is one open issue for the 2008 tax return for which an Appeals Conference is expected to take place in June 2010. The U.S. federal statute of limitations remains open for the year 2006 and onward. Years 2009 and 2010 are 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 by the end of 2010. Florida’s statute of limitations is three 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 Florida’s tax authorities include 2006 and onward. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

5. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. 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, 2010 and 2009, respectively, was $4.9 million and $3.4 million for pension benefits, and $3.6 million and $3.4 million for other postretirement benefits.

For the fiscal 2010 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.75% for pension benefits under its qualified pension plan, and a discount rate of 5.60% for its other postretirement benefits as of their Jan. 1, 2010 measurement dates. Additionally, TECO Energy assumed a discount rate of 5.75% for its Supplemental Executive Retirement Plan (SERP) benefits as of its Mar. 1 and Jan. 1, 2010 measurement dates.

Effective Dec. 31, 2006, in accordance with the accounting standard for defined benefit plans and other postretirement benefits, Tampa Electric Company adjusted its postretirement benefit obligations and recorded regulatory assets to reflect the unamortized transition obligation, prior service cost, and actuarial gains and losses of its postretirement benefit plans. Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2010, Tampa Electric Company reclassed $3.1 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

In March 2010, the Patient Protection and Affordability Care Act and a companion bill, The Health Care and Education Reconciliation Act were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, Tampa Electric Company reduced its deferred tax asset by $5.3 million and recorded a corresponding regulatory tax asset.

6. Short-Term Debt

At Mar. 31, 2010 and Dec. 31, 2009, the following credit facilities and related borrowings existed:

Credit Facilities

 

		Mar. 31, 2010									Dec. 31, 2009
(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		$	—		$	0.9		$	325.0		$	55.0		$	0.7
1-year accounts receivable facility			150.0			18.0			—			150.0			—			—
Total		$	475.0		$	18.0		$	0.9		$	475.0		$	55.0		$	0.7

 

(1)	Borrowings outstanding are reported as notes payable.

These credit facilities require commitment fees ranging from 7.0 to 60.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at both Mar. 31, 2010 and Dec. 31, 2009 was 0.64%.

 

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Tampa Electric Company Accounts Receivable Facility

On Feb. 19, 2010, Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 8 to the Loan and Servicing Agreement with certain lenders named therein and Citicorp North America, Inc. as Program Agent. The amendment (i) extends the maturity date to Feb. 18, 2011, (ii) provides that TRC will pay program and liquidity fees, which, pursuant to the amendment, will total 100 basis points, (iii) provides that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank offer rate (if available) plus a margin and (iv) makes other technical changes.

7. 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 accounting standards 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 Tampa Electric and PGS, is a potentially responsible party (PRP) for certain superfund sites and, through PGS, 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, 2010, Tampa Electric Company has estimated its ultimate financial liability to be approximately $19.9 million, primarily at PGS, 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 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 or 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

At Mar. 31, 2010, Tampa Electric Company was not obligated under guarantees, but had $0.9 million of letters of credit outstanding.

Letters of Credit -Tampa Electric Company

 

(millions)
Letters of Credit for the Benefit of:		2010			2011-2014(1)			After 2014			Total			Liabilities Recognized at Mar. 31, 2010
Tampa Electric
Letters of credit		$	—		$	—		$	0.9		$	0.9		$	—
Total		$	—		$	—		$	0.9		$	0.9		$	—

 

(1)	These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2014.

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, 2010, Tampa Electric Company was in compliance with applicable financial covenants.

 

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8. Segment Information

 

(millions) Three months ended Mar. 31,		Tampa Electric			Peoples Gas			Other & Eliminations				Tampa Electric Company
2010
Revenues - external		$	524.8		$	181.7		$	—			$	706.5
Sales to affiliates			0.3			11.2			(11.3	)			0.2
Total revenues			525.1			192.9			(11.3	)			706.7
Depreciation			53.0			11.4			—				64.4
Total interest charges			30.3			4.6			—				34.9
Provision for taxes			27.8			11.2			—				39.0
Net income		$	48.1		$	17.9		$	—			$	66.0
2009
Revenues - external		$	507.3		$	146.5		$	—			$	653.8
Sales to affiliates			0.3			6.5			(6.6	)			0.2
Total revenues			507.6			153.0			(6.6	)			654.0
Depreciation			48.0			10.8			—				58.8
Total interest charges			28.2			4.7			—				32.9
Provision for taxes			9.4			7.2			—				16.6
Net income		$	18.3		$	11.2		$	—			$	29.5
Total assets at Mar. 31, 2010		$	5,526.1		$	858.0		$	(23.3	)		$	6,360.8
Total assets at Dec. 31, 2009		$	5,457.5		$	826.0		$	(9.7	)		$	6,273.8

9. Accounting for Derivative Instruments and Hedging Activities

From time to time, Tampa Electric Company enters into futures, forwards, swaps and option contracts for the following purposes:

 

•

To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations; and

 

•

To limit the exposure to interest rate fluctuations on debt securities.

Tampa Electric Company uses derivatives only to reduce normal operating and market risks, not for speculative purposes. Tampa Electric Company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by Tampa Electric Company provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

Tampa Electric Company applies the accounting standards for derivatives and hedging. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

New accounting standards for disclosures became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. This new standard requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. The new requirements include qualitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. Tampa Electric Company adopted this new standard effective Jan. 1, 2009.

Tampa Electric Company applies accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for the regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities to reflect the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

A company’s physical contracts qualify for the normal purchase/normal sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Mar. 31, 2010, all of Tampa Electric Company’s physical contracts qualify for the NPNS exception.

 

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The following table presents the derivative hedges of natural gas contracts at Mar. 31, 2010 and Dec. 31, 2009 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

 

Natural Gas Derivatives
(millions)		Mar. 31, 2010			Dec. 31, 2009
Current assets		$	0.5		$	0.8
Long-term assets			—			—
Total assets		$	0.5		$	0.8
Current liabilities(1)		$	66.6		$	33.1
Long-term liabilities			8.1			3.6
Total liabilities		$	74.7		$	36.7

 

(1)	Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The ending balance in accumulated other comprehensive income (AOCI) related to previously settled interest rate swaps at Mar. 31, 2010 is a net loss of $5.9 million after tax and accumulated amortization. This compares to a net loss of $6.1 million in AOCI after tax and accumulated amortization at Dec. 31, 2009.

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Mar. 31, 2010:

 

Energy Related Derivatives
		Asset Derivatives					Liability Derivatives
(millions) at Mar. 31, 2010		Balance  Sheet Location(1)		Fair Value			Balance  Sheet Location(1)		Fair Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities		$	0.5		Regulatory assets		$	66.6
Long-term		Regulatory liabilities			—		Regulatory assets			8.1
Total				$	0.5				$	74.7

 

(1)

Natural gas derivatives are deferred in accordance with accounting standards for regulated operations and all increases and decreases in the cost of natural gas supply are passed on to customers with the fuel recovery clause mechanism. As gains and losses are realized in future periods, they will be recorded as fuel costs in the Consolidated Condensed Statements of Income.

Based on the fair value of the instruments at Mar. 31, 2010, net pretax losses of $66.1 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next twelve months.

 

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The following table presents the effect of hedging instruments on OCI and income for the three months ended Mar. 31:

 

(millions)		Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion(1)			Effective Portion(1)
2010
Interest rate contracts:		$	—		Interest expense		$	(0.2	)
Total		$	—				$	(0.2	)
2009
Interest rate contracts:		$	—		Interest expense		$	(0.2	)
Total		$	—				$	(0.2	)

 

(1)	Changes in OCI and AOCI are reported in after-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2010 and 2009, all hedges were effective.

The maximum length of time over which Tampa Electric Company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2012 for the financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Mar. 31, 2010, are expected to settle during the 2010, 2011 and 2012 fiscal years:

 

(millions)		Natural Gas Contracts (MMBTUs)
Year		Physical		Financial
2010		—		29.1
2011		—		20.7
2012		—		2.3
Total		—		52.1

Tampa Electric Company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. Tampa Electric Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause Tampa Electric Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, Tampa Electric Company could suffer a material financial loss. However, as of Mar. 31, 2010, substantially all of the counterparties with transaction amounts outstanding in Tampa Electric Company’s energy portfolio are rated investment grade by the major rating agencies. Tampa Electric Company assesses credit risk internally for counterparties that are not rated.

Tampa Electric Company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) Edison Electric Institute agreements (EEI) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - standardized physical gas contracts. Tampa Electric Company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

Tampa Electric Company has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. Tampa Electric Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are generally not adjusted as Tampa Electric Company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, Tampa Electric Company considers general market conditions and the observable financial health and outlook of specific

 

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counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of Mar. 31, 2010, substantially all positions with counterparties are net liabilities.

Certain of Tampa Electric Company’s derivative instruments contain provisions that require Tampa Electric Company’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. Tampa Electric Company has no other contingent risk features associated with any derivative instruments.

The table below presents the fair value of the overall contractual contingent liability positions for Tampa Electric Company’s derivative activity at Mar. 31, 2010:

 

Contingent Features
(millions) At Mar. 31, 2010		Fair Value Asset/ (Liability)				Derivative Exposure Asset/ (Liability)				Posted Collateral
Credit Rating		$	(74.2	)		$	(74.2	)		$	—

10. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy Tampa Electric Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2010. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Tampa Electric 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, 2010
(millions)		Level 1			Level 2			Level 3			Total
Assets
Natural gas swaps		$	—		$	0.5		$	—		$	0.5
Total		$	—		$	0.5		$	—		$	0.5
Liabilities
Natural gas swaps		$	—		$	74.7		$	—		$	74.7
Total		$	—		$	74.7		$	—		$	74.7
		At fair value as of Dec. 31, 2009
(millions)		Level 1			Level 2			Level 3			Total
Assets
Natural gas swaps		$	—		$	0.8		$	—		$	0.8
Total		$	—		$	0.8		$	—		$	0.8
Liabilities
Natural gas swaps		$	—		$	36.7		$	—		$	36.7
Total		$	—		$	36.7		$	—		$	36.7

Natural gas 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.

Tampa Electric Company considered the impact of nonperformance risk in determining the fair value of derivatives. Tampa Electric Company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Mar. 31, 2010, the fair value of derivatives was not materially affected by nonperformance risk. Tampa Electric Company's net positions with substantially all counterparties were liability positions.

Fair Value of Long-Term Debt

At Mar. 31, 2010, Tampa Electric Company’s total long-term debt had a carrying amount of $1,999.3 million and an estimated fair market value of $2,131.3 million. At Dec. 31, 2009, total long-term debt had a carrying amount of $1,999.4 million and an estimated fair market value of $2,115.4 million.

 

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11. Other Comprehensive Income

 

Other Comprehensive Income (millions)		Three months ended Mar. 31,
		Gross				Tax				Net
2010
Unrealized gain (loss) on cash flow hedges			—				—				—
Add: Loss reclassified to net income			0.3				(0.1	)			0.2
Gain on cash flow hedges			0.3				(0.1	)			0.2
Total other comprehensive income		$	0.3			$	(0.1	)		$	0.2
2009
Unrealized gain (loss) on cash flow hedges		$	—			$	—			$	—
Add: Loss reclassified to net income			0.3				(0.1	)			0.2
Gain on cash flow hedges			0.3				(0.1	)			0.2
Total other comprehensive income		$	0.3			$	(0.1	)		$	0.2
Accumulated Other Comprehensive Loss
(millions)		Mar. 31, 2010								Dec. 31, 2009
Net unrealized losses from cash flow hedges (1)		$	(5.9	)						$	(6.1	)
Total accumulated other comprehensive loss		$	(5.9	)						$	(6.1	)

 

(1)	Net of tax benefit of $3.7 million and $3.8 million as of Mar. 31, 2010 and Dec. 31, 2009, respectively.

12. Variable Interest Entities

Tampa Electric Company accounts for VIEs under accounting standards for consolidations. In accordance with these standards, the company evaluates for consolidation all long-term agreements with VIEs in which contractual, ownership or other pecuniary interests in that entity change with changes in the fair value of the entity’s net assets. A party to an agreement that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE, is considered to be the primary beneficiary and is required to consolidate that entity.

Tampa Electric Company has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interest entities. These risks include: operating and maintenance; regulatory; credit; commodity/fuel; and energy market risk. In most instances, Tampa Electric Company has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric Company is not required to consolidate any of these entities. Tampa Electric Company purchased $57.2 million and $42.2 million under these PPAs for the three months ended Mar. 31, 2010 and 2009, respectively.

In one instance Tampa Electric Company’s agreement with the entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of consolidation standards. Tampa Electric Company is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, under the contract have no obligation to do so and the information is not available publicly. As a result, Tampa Electric Company is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. Tampa Electric Company has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for Tampa Electric Company is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. The company purchased $12.7 million and $6.2 million under this PPA for the three months ended Mar. 31, 2010 and 2009, respectively.

Tampa Electric Company does not provide any material financial or other support to any of the VIEs it is involved with, nor is it under any obligation to absorb losses associated with these VIEs. Tampa Electric Company’s involvement with these VIEs does not affect our Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

 

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Item 2.

MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS

This Management’s Discussion & 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 Management’s Discussion and Analysis except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; the hearings before the FPSC in September on Tampa Electric’s 2010 portion of rate approved in 2009, and the intervenor’s appeal of that rate change to the Florida Supreme Court; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida economy and 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; operating conditions, commodity prices; operating cost and environmental or safety rule changes affecting the production levels and margins at TECO Coal; fuel cost recoveries and related cash at Tampa Electric and natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; changes in the U.S. federal tax code on earnings from foreign investments that could reduce earnings; the success of ongoing discussions with regulators in Guatemala to extend the purchase power agreement for the Alborada Power Station; and the ultimate outcome of efforts to revise the significantly lower EEGSA VAD tariff rates implemented by regulatory authorities in Guatemala effective Aug. 1, 2008 affecting TECO Guatemala’s results. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2009 and Item 1A “Risk Factors” of Part II of this Report.

Earnings Summary - Unaudited

 

		Three months ended Mar. 31,
(millions, except per share amounts)		2010			2009
Consolidated revenues		$	912.3		$	824.0
Net income attributable to TECO Energy		$	55.8		$	34.7
Average common shares outstanding
Basic			212.2			211.4
Diluted			213.9			212.2
Earnings per share - basic		$	0.26		$	0.16
Earnings per share - diluted		$	0.26		$	0.16

Operating Results

Three Months Ended Mar. 31, 2010

TECO Energy, Inc. reported first quarter 2010 net income attributable to TECO Energy of $55.8 million or $0.26 per share, compared to $34.7 million or $0.16 per share in the first quarter of 2009. As discussed in each subsidiary Operating Results section below, first quarter results in 2010 were reduced by charges of $16.2 million for early debt retirement and $0.9 million for restructuring; results in the first quarter of 2009 benefited from $5.1 million of net charges and gains, primarily the gain on the sale of the Guatemalan telecommunications provider, Navega.

Operating Company Results

All amounts included in the operating company and Parent/other results discussions are after tax, unless otherwise noted.

Due to an accounting rule change related to variable interest entities (VIEs), effective Jan. 1, 2010 the San José and Alborada power stations at TECO Guatemala were consolidated in the financial statements of TECO Energy. Prior periods have not been restated to reflect this change, which did not affect net income.

Tampa Electric Company – Electric Division

Net income for the first quarter was $48.1 million, compared with $18.3 million for the same period in 2009. Results for the quarter reflect significantly higher energy sales as a result of one of the coldest winters in the Tampa area in approximately 40 years. Results for the quarter also reflected higher base rates effective in May 2009 and the 2010 portion of rates approved by the Florida Public Service Commission (FPSC) in December, and lower operations and maintenance expenses discussed below. Net income included $1.0 million of Allowance for Funds Used During Construction (AFUDC) - equity, which represents allowed equity cost capitalized to construction costs, compared with $3.3 million in the 2009 period.

The pretax base revenue benefit from the exceptionally cold weather is estimated to be between $15 and $20 million for the 2010 quarter compared to the same period last year. Pretax base revenues increased between $25 and $30 million in the first quarter of 2010 due to the new base rates approved by the FPSC for Tampa Electric effective in May 2009 and on Jan. 1, 2010.

 

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Operations and maintenance expense, excluding all FPSC-approved cost recovery clauses, decreased $5.1 million, or about 9%, in the first quarter of 2010, compared to the same period in 2009, reflecting lower generating unit maintenance expenses due to the timing and scope of maintenance outages, lower expenses to operate the distribution system, and the benefits of the 2009 restructuring actions. Pension expense increased in the quarter, as expected, reflecting the impact of the 2008 financial market downturn on pension assets. Interest expense increased due to higher levels of outstanding long-term debt. Depreciation and amortization expense increased due to additions to facilities to serve customers, including the combustion turbines to meet peak load and the rail car unloading facilities at the Big Bend Power Station, all completed in 2009.

Tampa Electric’s retail energy sales increased 7.4% in the first quarter driven primarily by total heating and cooling degree days 37% above normal and 33% above 2009 levels, which drove an 18% increase in sales to the weather-sensitive residential customers. Sales to non-phosphate industrial customers declined almost 11%, reflecting the current Florida economic situation. Off-system sales declined due to lower coal-fired unit availability and the need to meet native load demand during the abnormally cold weather. The average number of customers increased 0.4% in the 2010 first quarter as a result of improvements in the Florida housing market, which appear to be driven by the home-buyer tax credit programs.

 

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A summary of Tampa Electric’s operating statistics for the three months ended Mar. 31, 2010 and 2009 follows:

 

		Operating Revenues											Kilowatt-hour sales
(millions, except average customers)		2010				2009				% Change			2010		2009		% Change
Three months ended Mar. 31,
By Customer Type
Residential		$	267.1			$	251.0			6.4			2,229.9		1,887.7		18.1
Commercial			147.1				166.3			(11.5	)		1,385.2		1,399.9		(1.1	)
Industrial – Phosphate			21.5				21.0			2.4			243.7		246.8		(1.3	)
Industrial – Other			24.0				29.3			(18.1	)		242.7		272.2		(10.8	)
Other sales of electricity			46.3				50.0			(7.4	)		430.9		414.5		4.0
Deferred and other revenues (1)			(3.4	)			(32.5	)		(89.5	)
			502.6				485.1			3.6			4,532.4		4,221.1		7.4
Sales for resale			9.9				12.1			(18.2	)		94.1		145.5		(35.3	)
Other operating revenue			12.4				10.4			19.2			—		—		—
NOx allowance sales			0.2				—			—			—		—		—
		$	525.1			$	507.6			3.4			4,626.5		4,366.6		6.0
Average customers (thousands)			669.9				667.3			0.4
Retail output to line (kilowatt hours)													4,636.1		4,362.6		6.3

 

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

Tampa Electric Company – Natural Gas Division (Peoples Gas)

Peoples Gas reported net income of $17.9 million for the first quarter, compared to $11.2 million in the same period in 2009. Pretax base revenues increased approximately $10 million due to the unusually cold winter weather and approximately $1 million due to the higher permanent base rates which became effective in June 2009. Quarterly results reflect a 0.2% higher average number of customers due to improvements in the Florida housing market, which appear to be driven by the home-buyer tax credit programs. Total therm sales increased 25% driven by 40% and 14% increases in sales to residential and commercial customers, respectively, due to the colder than normal winter weather. Higher therm sales to industrial customers reflect a return to service of a previously idled customer, and higher usage by other industrial customers. Gas transported for power generation customers and off-system sales increased in 2010 compared to the first quarter of 2009 due to high energy demands from the cold weather. Non-fuel operations and maintenance expense was essentially unchanged compared to 2009 levels. Results also reflect slightly higher depreciation and property tax expenses due to routine plant additions.

A summary of PGS’ regulated operating statistics for the three months ended Mar. 31, 2010 and 2009 follows:

 

		Operating Revenues									Therms
(millions, except average customers)		2010			2009			% Change			2010		2009		% Change
Three months ended Mar. 31,
By Customer Type
Residential		$	71.4		$	59.4		20.2			46.3		33.1		39.9
Commercial			50.1			47.2		6.1			125.3		110.1		13.8
Industrial			2.7			2.2		22.7			54.6		46.9		16.4
Off system sales			51.3			26.4		94.3			82.5		51.0		61.8
Power generation			2.3			2.7		(14.8	)		128.9		108.1		19.2
Other revenues			12.7			13.0		(2.3	)		—		—		—
Total		$	190.5		$	150.9		26.2			437.6		349.2		25.3
By Sales Type
System supply		$	148.9		$	113.7		31.0			146.1		102.2		43.0
Transportation			28.9			24.2		19.4			291.5		247.0		18.0
Other revenues			12.7			13.0		(2.3	)		—		—		—
Total		$	190.5		$	150.9		26.2			437.6		349.2		25.3
Average customers (thousands)			336.4			335.6		0.2

 

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TECO Coal

TECO Coal reported first quarter net income of $16.8 million, compared to $8.0 million in the same period in 2009. Results in 2010 included a $3.3 million benefit from the settlement of state income tax issues recorded in prior years.

In 2010, first quarter sales were 2.1 million tons, compared to 2.3 million tons in the first quarter of 2009. Results reflected an average net per ton selling price, excluding transportation allowances, of more than $76 per ton, almost 10% higher than in 2009. First quarter sales volumes were affected by rail shipment disruptions throughout Central Appalachia from severe winter weather in January and February. Shipping volumes partially recovered in March and full-year sales are expected to be at previously forecasted levels. In the first quarter of 2010, the all-in total per ton cost of production was $68 per ton, an increase of less than 4% over 2009’s level and within the cost guidance range previously provided. Costs increased in the first quarter primarily due to the timing of certain surface mine reclamation activities early in the year and lost productivity due to winter weather. TECO Coal’s effective income tax rate in the first quarter of 2010 was 23%, excluding the effect of the state income tax settlement, compared to 14% in the 2009 Period.

On Apr. 1, 2010, the U.S. Environmental Protection Agency (EPA) issued new guidance on environmental permitting requirements for Appalachian mountain top removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and will be effective immediately on an interim basis. The EPA will decide whether to modify the guidance after consideration of public comments and the results of the Science Advisory Board (SAB) technical review of the EPA scientific reports. Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. If this guidance becomes a regulation, or is enforced like one, it is expected to face legal challenges relating to the stringency of the standards as well as the focus on the coal industry and the Appalachian region in particular.

TECO Guatemala

TECO Guatemala reported first quarter net income of $10.4 million in 2010, compared to $13.2 million in the 2009 period. TECO Guatemala’s first quarter 2009 included the $8.7 million gain from the sale of the telecommunications service provider, Navega, which was sold in the first quarter of 2009. The improved 2010 first quarter results reflect a full quarter of normal operations for the San José Power Station, compared to the first quarter of 2009 when the plant experienced unplanned outages for much of the quarter. Improved availability allowed for higher spot energy sales at higher margins driven by the current high cost of residual fuel oil, which sets the market clearing price, and lower than normal power supplies from hydro-electric sources. Higher net income from normal operations and spot energy sales was partially offset by $2.0 million lower capacity payments under the power sales contract. Capacity payments for the San José Power Station are based on a 12-month rolling average availability, and were reduced starting in the second half of 2009 as a result of the unplanned outages in the first six months of 2009. At EEGSA, the distribution utility, 2010 first quarter results reflect the benefit of customer growth, higher energy sales, and cost control measures to offset the impact of the lower distribution tariff implemented in August 2008. Higher earnings at the remaining DECA II unregulated EEGSA-affiliated companies, which provide, among other things, electricity transmission services, wholesale power sales to unregulated electric customers and engineering services, were more than offset by the absence of Navega earnings after its sale.

Other and Eliminations

Parent/other cost in the first quarter was $37.4 million, compared to a cost of $16.0 million for the 2009 period. The cost in 2010 included a $16.2 million charge related to the early debt retirement described below, and a $0.9 million charge related to the 2009 restructuring activities. The cost in 2010 also included a $5.2 million negative valuation adjustment to foreign tax credits based on estimated foreign source income and projected timing of the utilization of the net operating loss (NOL) carry forwards, and a $1.1 million charge to adjust deferred tax balances related to the Medicare Part D subsidies as a result of the recently enacted Patient Protection and Affordability Care Act. The cost in the 2009 period included a $3.6 million valuation adjustment on student loan securities held at TECO Energy parent.

Income Taxes

The provisions for income taxes from continuing operations for the three month periods ended Mar. 31, 2010 and Mar. 31, 2009 were $34.3 million and $17.8 million, respectively. The provision for income taxes from continuing operations in the three months ended Mar. 31, 2010 was impacted by the foreign tax credit valuation allowance.

Liquidity and Capital Resources

The table below sets forth the Mar. 31, 2010 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.

 

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		Balances as of Mar. 31, 2010
(millions)		Consolidated			Tampa Electric Company			Other			Parent
Credit facilities		$	675.0		$	475.0		$	—		$	200.0
Drawn amounts / LCs			25.6			18.9			—			6.7
Available credit facilities			649.4			456.1			—			193.3
Cash and short-term investments			230.9			13.9			31.9			185.1
Total liquidity		$	880.3		$	470.0		$	31.9		$	378.4

In the first quarter, TECO Energy and TECO Finance tendered for, purchased and retired a total of $300 million aggregate principal amount of 7.00% and 7.20% TECO Energy and TECO Finance notes, and TECO Finance issued $250 million aggregate principal amount of 4.00% notes due in 2016 and $300 million aggregate principal amount of 5.15% notes due in 2020, which notes are fully and unconditionally guaranteed by TECO Energy. In April 2010, TECO Energy redeemed all of the outstanding $100 million aggregate principal amount of its floating rate notes due May 2010 and $100 million aggregate principal amount of its 7.20% notes due in 2011.

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, TECO Finance, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2010, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Mar. 31, 2010. Reference is made to the specific agreements and instruments for more details.

 

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Significant Financial Covenants

 

(millions, unless otherwise indicated) Instrument		Financial Covenant (1)		Requirement/Restriction		Calculation at Mar. 31, 2010
Tampa Electric Company
PGS senior notes (7)		EBIT/interest (2)		Minimum of 2.0 times		3.6 times
		Restricted payments		Shareholder equity at least $500		$2,164
		Funded debt/capital		Cannot exceed 65%		49.4%
		Sale of assets		Less than 20% of total assets		0%
Credit facility (3)		Debt/capital		Cannot exceed 65%		48.2%
Accounts receivable credit facility (3)		Debt/capital		Cannot exceed 65%		48.2%
6.25% senior notes		Debt/capital		Cannot exceed 60%		48.2%
		Limit on liens (4)		Cannot exceed $700		$0 liens outstanding
Insurance agreements relating to certain pollution bonds		Limit on liens (4)		Cannot exceed $432 (7.5% of net assets)		$0 liens outstanding
TECO Energy/TECO Finance
Credit facility (3)		EBITDA/interest (2)		Minimum of 2.6 times		4.2 times
TECO Energy floating rate and 6.75% notes and TECO Finance 6.75% notes		Restrictions on secured debt (6)		(5)		(5)
TECO Diversified
Coal supply agreement guarantee (8)		Dividend restriction		Net worth not less than $307 (40% of tangible net assets)		$562

 

(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 2009 TECO Energy, Inc. Annual Report on Form 10-K.

(4)	If the limitation on liens is exceeded, the company is required to provide ratable security to the holders of these notes.

(5)	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.

(6)	These limitations would not include first mortgage bonds of Tampa Electric Company if any were outstanding.

(7)	Principal amount outstanding of these notes totaled $10.5 million at Mar. 31, 2010, well below any cross default thresholds in various debt agreements.

(8)	Limits the payment of dividends to TECO Energy, but does not limit loans or advances.

Credit Ratings of Senior Unsecured Debt at Mar. 31, 2010

 

		Standard & Poor’s		Moody’s		Fitch
Tampa Electric Company		BBB		Baa1		BBB+
TECO Energy/TECO Finance		BBB-		Baa3		BBB-

 

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Off-Balance Sheet Financing

Unconsolidated affiliates have project debt balances as follows at Mar. 31, 2010. 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 is at risk if those projects are not operated successfully.

 

(millions)		Long-term Debt		Ownership Interest
DECA II		$177.7		24%

2010 Guidance and Business Drivers

TECO Energy is maintaining its 2010 earnings per share guidance range between $1.20 and $1.35, excluding charges and gains. TECO Energy expects earnings in 2010 to be driven by the factors discussed below.

Tampa Electric and Peoples Gas have combined the organizations under a single management team with new organizational structures following the restructuring actions taken in the third quarter of 2009. These actions have reduced Tampa Electric’s expected operations and maintenance expenses in 2010 to approximately 2008 levels to offset the approximately $40 million revenue shortfall compared to the revenue projections filed in its base rate case. These restructuring actions are expected to enable the utilities to earn the authorized returns on equity set in the respective 2009 rate case decisions.

Tampa Electric and Peoples Gas will have the full year benefit of the 2009 base rate increases implemented in 2009. In addition, the FPSC approved a $26 million base rate increase related to the five combustion turbines and the rail unloading facilities placed in service in 2009, with rates effective Jan. 1, 2010 subject to refund pending the outcome of a hearing on that increase to be held by the FPSC in 2010. The hearing is scheduled for Sep. 1 and 2, and a Commission vote is expected in early November.

The forecast for Tampa Electric and Peoples Gas assumes normal weather for the remainder of the year. The outlook and timing for a Florida economic recovery remains uncertain due to high unemployment and an uncertain housing market. Year-to-date housing market improvements appear to be driven by the home-buyer tax credit programs. The strength of the housing market is uncertain after the expiration of these tax credits at mid-year. Economists continue to forecast a very slow recovery in employment starting in 2010, while others are forecasting a flat economy for 2010. The forecast used by Tampa Electric and Peoples Gas reflects a slight decline in energy sales due to continued weakness in the commercial and industrial sectors and lower customer usage in response to the continued weak economy.

Due to the current strong markets for metallurgical and pulverized coal injection coals, TECO Coal now expects its sales in 2010 to be near the upper end of the previously provided production sales range of 8.3 to 8.7 million tons. The total expected sales are contracted and priced at an average price of more than $75 per ton. More than one-third of sales are to steel producers and specialty stoker coal users with the remainder sold to utility steam coal customers. The all-in, fully-loaded production costs are expected to be in a range between $65 and $69 per ton, driven by lower diesel fuel costs offset by higher safety requirements, lower productivity that reflects the industry-wide trend of increased inspections by state and federal agencies, and higher royalty cost and severance taxes due to the higher selling prices. Diesel fuel prices have been hedged for those contracts that do not have diesel price adjustments in the contract at average prices below 2009 levels. Production costs may be negatively impacted if there are increased mine safety requirements as a result of the recent mine tragedy in West Virginia.

TECO Guatemala expects improved operating and financial performance at the San José Power Station following the extended unplanned outages in 2009, and higher contract capacity payments, which are expected to increase as the 12-month rolling average availability factor improves. Assuming a return to more normal hydro-electric operating conditions, spot energy sales from the San José Power Station are expected to return to more normal levels for the remainder of the year. EEGSA, the Guatemalan distribution utility, continues to experience customer and energy sales growth, but the issue with the value added distribution tariff (VAD), which was reduced by the Guatemalan regulators in August 2008, remains unresolved. Iberdrola, EEGSA’s largest investor, is in an international arbitration process under the bilateral trade agreement between Spain and Guatemala. At this time, there is no firm schedule to resolve this matter. TECO Guatemala is currently in discussions with the Guatemalan regulatory authorities regarding the five-year extension of the power sales contract for the Alborada Power Station, which expires in September 2010.

This guidance is provided in the form of a range to allow for varying outcomes with respect to important variables, such as the timing of the start of and the strength of an economic and housing market recovery in Florida, weather and customer usage at the Florida utilities, steam coal inventories at TECO Coal’s utility customers and their ability to accept contracted amounts, and margins at TECO Coal.

Fair Value Measurements

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying accounting standards for regulated operations, 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.

Heating oil hedges are used to mitigate the fluctuations in the price of diesel fuel which is a significant component in the cost of coal production at TECO Coal and its subsidiaries.

 

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Index to Financial Statements

The valuation methods we used to determine fair value are described in Note 13 to the TECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Mar. 31, 2010 the fair value of derivatives was not materially affected by nonperformance risk. Our net positions with substantially all counterparties were liability positions.

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, 2009.

 

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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.

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 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 2010 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 change in fair value of derivatives is largely due to the decrease in the price of natural gas of approximately 20% from Dec. 31, 2009 to Mar. 31, 2010. For natural gas, the company maintains a similar volume hedged as of Mar. 31, 2010 from Dec. 31, 2009.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three months ended Mar. 31, 2010:

 

Changes in Fair Value of Derivatives (millions)
Net fair value of derivatives as of Dec. 31, 2009		$	(36.6	)
Additions and net changes in unrealized fair value of derivatives			(58.5	)
Changes in valuation techniques and assumptions			—
Realized net settlement of derivatives			20.0
Net fair value of derivatives as of Mar. 31, 2010		$	(75.1	)
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2009		$	(36.6	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income			(58.5	)
Recorded in earnings			—
Realized net settlement of derivatives			20.0
Net option premium payments			—
Net purchase (sale) of existing contracts			—
Net fair value of derivatives as of Mar. 31, 2010		$	(75.1	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Mar. 31, 2010:

 

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Mar. 31, 2010 (millions)
Contracts Maturing in		Current				Non-current				Total Fair Value
Source of fair value
Actively quoted prices		$	—			$	—			$	—
Other external sources (1)			(67.3	)			(7.8	)			(75.1	)
Model prices (2)			—				—				—
Total		$	(67.3	)			(7.8	)			(75.1	)

(1)	Reflects over-the-counter natural gas or heating oil swaps for which the primary pricing inputs in determining fair value are NYMEX quoted closing prices of exchange traded instruments.

(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.

 

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Index to Financial Statements

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 control over financial reporting 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 control over financial reporting that occurred during Tampa Electric Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

 

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Index to Financial Statements

PART II. OTHER INFORMATION

 

Item 1A.

RISK FACTORS

New water quality standards recently announced by the EPA could potentially curtail the issuance of future surface mine permits and mining activity at TECO Coal, which could adversely affect its production and financial results.

On Apr. 1, 2010, the U.S. Environmental Protection Agency (EPA) issued new guidance on environmental permitting requirements for Appalachian mountain top removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and is effective immediately on an interim basis. The EPA will decide whether to modify the guidance after consideration of public comments and the results of the Science Advisory Board (SAB) technical review of the EPA scientific reports. Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. If this guidance becomes a regulation, or is enforced like one, it is expected to face legal challenges relating to the stringency of the standards as well as the focus on the coal industry and the Appalachian region in particular. Any curtailment of TECO Coal’s mining activities as a result of these new water standards could have an adverse effect on TECO Coal’s financial results.

 

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, 2010 – Jan. 31, 2010		1,492		$	15.74		—		—
Feb. 1, 2010 – Feb. 28, 2010		25,286		$	15.59		—		—
Mar. 1, 2010 – Mar. 31, 2010		448		$	15.76		—		—
Total 1st Quarter 2010		27,226		$	15.60		—		—

 

(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 54.

 

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Index to Financial Statements

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)
Date: May 6, 2010				By:		/s/ S. W. CALLAHAN
						S. W. CALLAHAN
						Vice President-Finance and Accounting and Chief Financial Officer
						(Chief Accounting Officer)
						(Principal Financial and Accounting Officer)
				TAMPA ELECTRIC COMPANY
				(Registrant)
Date: May 6, 2010				By:		/s/ S. W. CALLAHAN
						S. W. CALLAHAN
						Vice President-Finance and Accounting and Chief Financial Officer
						(Chief Accounting Officer)
						(Principal Financial and Accounting Officer)

 

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Index to Financial Statements

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 Oct. 29, 2009 (Exhibit 3.1, Form 8-K dated Oct. 29, 2009 of TECO Energy, Inc.).		*
3.3		Articles of Incorporation of Tampa Electric Company (Exhibit 3 to 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		Third Supplemental Indenture dated as of Mar. 15, 2010 by and among TECO Finance, Inc., as issuer, TECO Energy, Inc.,) as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee, (including the form of TECO Finance notes to be issued thereunder) supplementing the Indenture dated as of Dec. 21, 2007 (Exhibit 4.26, Form 8-K dated Mar. 15, 2010 of TECO Energy, Inc.).		*
4.2		4.00% Notes due 2016 (Exhibit 4.27, Form 8-K dated Mar. 15, 2010 of TECO Energy, Inc.).		*
4.3		5.15% Notes due 2020 (Exhibit 4.28, Form 8-K dated Mar. 15, 2010 of TECO Energy, Inc.).		*
10.1		Change-in-Control Severance Agreement between TECO Energy, Inc. and Sandra W. Callahan (Exhibit 10.1, Form 8-K dated Feb. 5, 2010 of TECO Energy, Inc.).		*
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.

 

53