TECO Energy 10-Q 2012 Q2 Quarterly report

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 endedJune 30, 2012

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 website, 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  x    NO  ¨

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

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

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

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

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

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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of July 27, 2012 was 216,583,178. As of July 27, 2012, 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 56

Index to Exhibits appears on page 56.

DEFINITIONS

Acronyms and defined terms used in this and other filings with the U.S. Securities and Exchange Commission include the following:

Term	Meaning
ABS	asset-backed security
ADR	American depository receipt
AFUDC	allowance for funds used during construction
AFUDC - debt	debt component of allowance for funds used during construction
AFUDC - equity	equity component of allowance for funds used during construction
AOCI	accumulated other comprehensive income
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
capacity clause	capacity cost-recovery clause, as established by the FPSC
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980
CGESJ	Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala
CMO	collateralized mortgage obligation
CO2	carbon dioxide
CT	combustion turbine
DECA II	Distribución Eléctrica Centro Americana, II, S.A.
DOE	U.S. Department of Energy
EEGSA	Empresa Eléctrica de Guatemala, S.A., the largest private distribution company in Central America
EEI	Edison Electric Institute
EPA	U.S. Environmental Protection Agency
EPS	earnings per share
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
ERP	enterprise resource planning
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company
FPSC	Florida Public Service Commission
fuel clause	fuel and purchased power cost-recovery clause, as established by the FPSC
GAAP	generally accepted accounting principles
GHG	greenhouse gas(es)
HCIDA	Hillsborough County Industrial Development Authority
HPP	Hardee Power Partners
IFRS	International Financial Reporting Standards
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISO	independent system operator
ITCs	investment tax credits
kW	kilowatt
kWh	kilowatt-hour(s)
LIBOR	London Interbank Offered Rate
MARN	Ministry of Environment, Guatemala
MBS	mortgage-backed securities
MD&A	Management’s Discussion and Analysis
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MM&A	Marshall Miller & Associates

2

MMBTU	one million British Thermal Units
MRV	market-related value
MSHA	Mine Safety and Health Administration
MW	megawatt(s)
MWH	megawatt-hour(s)
NAESB	North American Energy Standards Board
NAV	net asset value
NERC	North American Electric Reliability Corporation
NOL	net operating loss
Note	Note    to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
o&m expenses	operations and maintenance expenses
OATT	open access transmission tariff
OCI	other comprehensive income
OTC	over-the-counter
OTTI	other than temporary impairment
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PCIDA	Polk County Industrial Development Authority
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
REIT	real estate investment trust
REMIC	real estate mortgage investment conduit
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
RPS	renewable portfolio standards
RTO	regional transmission organization
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SERP	Supplemental Executive Retirement Plan
SPA	stock purchase agreement
STIF	short-term investment fund
TCAE	Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TEC	Tampa Electric Company, the principal subsidiary of TECO Energy, Inc.
TECO Diversified	TECO Diversified, Inc., a subsidiary of TECO Energy, Inc. and parent of TECO Coal Corporation
TECO Coal	TECO Coal Corporation, a coal producing subsidiary of TECO Diversified
TECO Finance	TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.
TEMSA	Tecnología Marítima, S.A., a provider of dry bulk and coal unloading services located in Guatemala
TRC	TEC Receivables Company
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

3

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 June 30, 2012 and Dec. 31, 2011, and the results of their operations and cash flows for the periods ended June 30, 2012 and 2011. The results of operations for the three month and six month periods ended June 30, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012. 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, 2011 and to the notes on pages 10 through 29 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, June 30, 2012 and Dec. 31, 2011		5-6
Consolidated Condensed Statements of Income for the three month and six month periods ended June  30, 2012 and 2011		7-8
Consolidated Condensed Statements of Comprehensive Income for the three month and six month periods ended June 30, 2012 and 2011		9
Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2012 and 2011		10
Notes to Consolidated Condensed Financial Statements		11-27

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

4

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	June 30 2012			Dec. 31, 2011
Current assets
Cash and cash equivalents	$	117.4		$	44.0
Restricted cash		14.2			8.7
Receivables, less allowance for uncollectables of $2.6 at June 30, 2012 and Dec. 31, 2011		330.5			327.7
Inventories, at average cost
Fuel		166.1			136.8
Materials and supplies		88.8			87.3
Derivative assets		0.7			0.9
Regulatory assets		83.2			87.3
Deferred income taxes		43.1			72.7
Prepayments and other current assets		43.5			31.9
Income tax receivables		0.1			0.6
Total current assets		887.6			797.9
Property, plant and equipment
Utility plant in service
Electric		6,821.3			6,731.7
Gas		1,197.2			1,169.9
Construction work in progress		284.0			247.4
Other property		438.4			432.3
Property, plant and equipment, at original costs		8,740.9			8,581.3
Accumulated depreciation		(2,718.3	)		(2,613.5	)
Total property, plant and equipment, net		6,022.6			5,967.8
Other assets
Regulatory assets		351.1			364.5
Derivative assets		0.1			0.0
Goodwill		55.4			55.4
Deferred charges and other assets		133.8			136.6
Total other assets		540.4			556.5
Total assets	$	7,450.6		$	7,322.2

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

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)	June 30, 2012			Dec. 31, 2011
Current liabilities
Long-term debt due within one year
Recourse	$	256.4		$	374.9
Non-recourse		11.2			11.2
Notes payable		20.0			0.0
Accounts payable		207.2			252.3
Customer deposits		161.4			159.5
Regulatory liabilities		83.4			86.2
Derivative liabilities		40.5			58.4
Interest accrued		42.8			39.3
Taxes accrued		51.5			20.7
Other current liabilities		17.2			17.2
Total current liabilities		891.6			1,019.7
Other liabilities
Deferred income taxes		178.9			150.8
Investment tax credits		9.9			10.0
Regulatory liabilities		654.1			647.8
Derivative liabilities		3.9			8.6
Deferred credits and other liabilities		522.4			530.8
Long-term debt, less amount due within one year
Recourse		2,878.4			2,665.0
Non-recourse		16.7			22.3
Total other liabilities		4,264.3			4,035.3
Commitments and Contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized par value $1; 216.6 million shares and 215.8 million shares outstanding at June 30, 2012 and Dec. 31, 2011, respectively)		216.6			215.8
Additional paid in capital		1,557.1			1,553.4
Retained earnings		547.9			519.4
Accumulated other comprehensive loss		(27.3	)		(22.0	)
TECO Energy capital		2,294.3			2,266.6
Noncontrolling interest		0.4			0.6
Total capital		2,294.7			2,267.2
Total liabilities and capital	$	7,450.6		$	7,322.2

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Three months ended June 30,
(millions, except per share amounts)	2012			2011
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $28.3 in 2012 and $27.1 in 2011)	$	600.3		$	656.5
Unregulated		188.1			229.2
Total revenues		788.4			885.7
Expenses
Regulated operations
Fuel		167.9			194.2
Purchased power		31.2			43.9
Cost of natural gas sold		36.4			54.1
Other		85.6			82.1
Operation other expense
Mining related costs		99.1			130.7
Guatemalan power generation		20.4			22.7
Other		1.1			1.7
Maintenance		43.8			48.5
Depreciation and amortization		84.2			81.2
Taxes, other than income		57.1			55.5
Total expenses		626.8			714.6
Income from operations		161.6			171.1
Allowance for other funds used during construction		0.5			0.3
Other income		1.9			1.5
Total other income		2.4			1.8
Interest charges
Interest expense		50.3			51.3
Allowance for borrowed funds used during construction		(0.3	)		(0.1	)
Total interest charges		50.0			51.2
Income before provision for income taxes		114.0			121.7
Provision for income taxes		40.9			44.1
Net income	$	73.1		$	77.6
Less: Net income attributable to noncontrolling interest		0.0			(0.1	)
Net income attributable to TECO Energy	$	73.1		$	77.5
Average common shares outstanding – Basic		214.3			213.6
– Diluted		215.2			215.2
Earnings per share attributable to TECO Energy – Basic	$	0.34		$	0.36
– Diluted	$	0.34		$	0.36
Dividends paid per common share outstanding	$	0.220		$	0.215

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Six months ended June 30,
(millions, except per share amounts)	2012			2011
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $54.4 in 2012 and $55.5 in 2011)	$	1,156.6		$	1,243.6
Unregulated		361.8			438.2
Total revenues		1,518.4			1,681.8
Expenses
Regulated operations
Fuel		325.4			339.1
Purchased power		59.4			71.1
Cost of natural gas sold		78.0			136.1
Other		168.9			160.4
Operation other expense
Mining related costs		188.5			254.7
Guatemalan power generation		39.6			42.8
Other		3.7			3.1
Maintenance		87.8			97.3
Depreciation and amortization		167.2			161.0
Taxes, other than income		113.1			114.2
Total expenses		1,231.6			1,379.8
Income from operations		286.8			302.0
Other income
Allowance for other funds used during construction		0.9			0.6
Other income		3.9			3.0
Total other income		4.8			3.6
Interest charges
Interest expense		100.9			104.1
Allowance for borrowed funds used during construction		(0.5	)		(0.3	)
Total interest charges		100.4			103.8
Income before provision for income taxes		191.2			201.8
Provision for income taxes		67.5			72.5
Net income	$	123.7		$	129.3
Less: Net income attributable to noncontrolling interest		(0.1	)		(0.1	)
Net income attributable to TECO Energy	$	123.6		$	129.2
Average common shares outstanding – Basic		214.1			213.3
– Diluted		215.3			215.1
Earnings per share attributable to TECO Energy – Basic	$	0.58		$	0.60
– Diluted	$	0.57		$	0.60
Dividends paid per common share outstanding	$	0.440		$	0.420

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended June 30,						Six months ended June 30,
(millions)	2012			2011			2012			2011
Net income	$	73.1		$	77.6		$	123.7		$	129.3
Other comprehensive income (loss), net of tax
Net unrealized (losses) gains on cash flow hedges		(7.4	)		(1.4	)		(5.9	)		0.9
Amortization of unrecognized benefit costs and other		0.5			0.4			0.6			0.8
Other comprehensive (loss) income, net of tax		(6.9	)		(1.0	)		(5.3	)		1.7
Comprehensive income		66.2			76.6			118.4			131.0
Comprehensive income attributable to noncontrolling interest		0.0			(0.1	)		(0.1	)		(0.1	)
Comprehensive income attributable to TECO Energy, Inc.	$	66.2		$	76.5		$	118.3		$	130.9

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

9

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended June 30,
(millions)	2012			2011
Cash flows from operating activities
Net income	$	123.7		$	129.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		167.2			161.0
Deferred income taxes		63.4			69.0
Investment tax credits		(0.1	)		(0.2	)
Allowance for funds used during construction		(0.9	)		(0.6	)
Non-cash stock compensation		5.3			4.2
Deferred recovery clauses		(12.9	)		6.3
Receivables, less allowance for uncollectibles		(2.8	)		(2.0	)
Inventories		(30.8	)		13.8
Prepayments and other current assets		(11.6	)		(3.5	)
Taxes accrued		31.3			22.3
Interest accrued		3.5			4.6
Accounts payable		(26.9	)		(34.6	)
Other		(3.0	)		17.2
Cash flows from operating activities		305.4			386.8
Cash flows from investing activities
Capital expenditures		(240.9	)		(200.2	)
Allowance for funds used during construction		0.9			0.6
Other investing activities		0.0			17.3
Cash flows used in investing activities		(240.0	)		(182.3	)
Cash flows from financing activities
Dividends		(95.1	)		(90.4	)
Proceeds from the sale of common stock		3.2			5.4
Proceeds from long-term debt issuance		290.3			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(210.1	)		(144.6	)
Dividend to noncontrolling interest		(0.3	)		(0.6	)
Net increase in short-term debt		20.0			20.0
Cash flows from (used in) financing activities		8.0			(210.2	)
Net increase (decrease) in cash and cash equivalents		73.4			(5.7	)
Cash and cash equivalents at beginning of period		44.0			67.5
Cash and cash equivalents at end of period	$	117.4		$	61.8

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

10

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See the company’s 2011 Annual Report on Form 10-K for a complete detailed discussion of 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 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. For the periods presented, no VIEs have been consolidated (seeNote 14).

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 its subsidiaries as of June 30, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended June 30, 2012 and 2011. The results of operations for the three and six month periods ended June 30, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. 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 U.S. GAAP.

Revenues

As of June 30, 2012 and Dec. 31, 2011, unbilled revenues of $54.1 million and $50.2 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TECO Coal incurs most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices 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. 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 amounts totaled $28.3 million and $54.4 million, respectively, for the three and six months ended June 30, 2012, compared to $27.1 million and $55.5 million, respectively, for the three and six months ended June 30, 2011.

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 diesel fuel swaps, which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating 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

Offsetting Assets and Liabilities

In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. The company will adopt this guidance as required. It will have no effect on the company’s results of operations, financial 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 FERC under the 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

11

under the PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations 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 to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $47.6 million and $43.6 million as of June 30, 2012 and Dec. 31, 2011, respectively.

Wholesale and Transmission Rate Cases

In July 2012, the FERC approved the uncontested settlement that Tampa Electric filed with its customers in its wholesale requirements rate case earlier this year. The approved settlement will take effect in August and Tampa Electric will refund its wholesale requirements’ customers the appropriate amounts given the terms of the settlement. Tampa Electric awaits FERC approval for its uncontested transmission rate case settlement, which was filed with FERC also earlier this year. The wholesale requirements and transmission rate case settlements’ rates will not have a material impact on Tampa Electric’s results.

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.

Details of the regulatory assets and liabilities as of June 30, 2012 and Dec. 31, 2011 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	June 30, 2012		Dec. 31, 2011
Regulatory assets:
Regulatory tax asset(1)	$	62.5	$	63.6
Other:
Cost-recovery clauses		58.6		73.3
Postretirement benefit asset		245.2		252.4
Deferred bond refinancing costs(2)		9.1		11.1
Environmental remediation		37.7		30.5
Competitive rate adjustment		3.5		3.5
Other		17.7		17.4
Total other regulatory assets		371.8		388.2
Total regulatory assets		434.3		451.8
Less: Current portion		83.2		87.3
Long-term regulatory assets	$	351.1	$	364.5
Regulatory liabilities:
Regulatory tax liability(1)	$	15.3	$	16.0
Other:
Cost-recovery clauses		58.7		61.4
Environmental remediation		28.4		28.4
Transmission and delivery storm reserve		47.6		43.6
Deferred gain on property sales(3)		4.1		5.0
Provision for stipulation and other		1.0		0.8
Accumulated reserve - cost of removal		582.4		578.8
Total other regulatory liabilities		722.2		718.0
Total regulatory liabilities		737.5		734.0
Less: Current portion		83.4		86.2
Long-term regulatory liabilities	$	654.1	$	647.8

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

12

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

(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)	June 30, 2012		Dec 31, 2011
Clause recoverable(1)	$	62.1	$	76.8
Components of rate base(2)		258.5		264.9
Regulatory tax assets(3)		62.5		63.6
Capital structure and other(3)		51.2		46.5
Total	$	434.3	$	451.8

(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.

4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2010 consolidated federal income tax return during 2011. The U.S. federal statute of limitations remains open for years 2008 and forward. Years 2011 and 2012 are currently under examination by the IRS under their Compliance Assurance Program. 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 2012. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2006 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense-Other” on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. For the six months ended June 30, 2012, the company recorded $0.1 million of pretax charges for interest only and an immaterial amount for penalties.

The effective tax rate decreased to 35.29% for the six months ended June 30, 2012 from 35.92% for the same period in 2011. The decrease is principally due to state income taxes.

13

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 June 30,	2012			2011			2012		2011
Components of net periodic benefit expense
Service cost	$	4.1		$	3.8		$	0.5	$	0.5
Interest cost on projected benefit obligations		7.6			7.7			2.6		2.7
Expected return on assets		(8.9	)		(9.5	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.5		0.6
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.2
Actuarial loss (gain)		3.9			2.8			0.0		(0.1	)
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	6.6		$	4.7		$	3.8	$	3.9
Six months ended June 30,
Components of net periodic benefit expense
Service cost	$	8.5		$	8.0		$	1.2	$	1.1
Interest cost on projected benefit obligations		15.0			15.5			5.1		5.5
Expected return on assets		(18.5	)		(19.2	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.9		1.2
Prior service (benefit) cost		(0.2	)		(0.2	)		0.4		0.4
Actuarial loss		7.6			5.6			0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	12.4		$	9.7		$	7.6	$	8.2

For the fiscal 2012 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.797% for pension benefits under its qualified pension plan, and a discount rate of 4.744% for its other postretirement benefits as of their Jan. 1, 2012 measurement dates. Additionally, TECO Energy made contributions of $20.1 million to its pension plan for the six months ended June 30, 2012.

For the three and six months ended June 30, 2012, TECO Energy and its subsidiaries reclassed $0.8 million and $1.5 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and six months ended June 30, 2012, TEC reclassed $3.8 million and $7.3 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

In July 2012, the President signed into law the Moving Ahead for Progress in the 21st Century Act (MAP-21). MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company is currently evaluating the impact MAP-21 will have on its pension contributions and on future PBGC premiums, and expects the required minimum pension contributions to be lower than the levels previously projected.

14

6. Short-Term Debt

At June 30, 2012 and Dec. 31, 2011, the following credit facilities and related borrowings existed:

Credit Facilities
	June 30, 2012						Dec. 31, 2011
(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(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	0.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility(2)(3)		200.0		20.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	20.0	$	0.7	$	675.0	$	0.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Oct. 25, 2016.

(3) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

At June 30, 2012, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at June 30, 2012 was 1.080%. There were no outstanding borrowings at Dec. 31, 2011.

Tampa Electric Company Accounts Receivable Facility

On Feb. 17, 2012, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 10 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 15, 2013, (ii) provides that TRC will pay program and liquidity fees, which will total 60 basis points, (iii) continues to provide 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 TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

7. Long-Term Debt

Issuance of Tampa Electric Company 4.10% Notes due 2042

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the Notes). The Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the Notes at its option 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. At any time on or after Dec. 15, 2041, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) and Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the HCIDA Bonds). On March 19, 2008, the HCIDA remarketed the HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the HCIDA Bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation.

15

On March 1, 2011, TEC purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously were in auction rate mode and were held by TEC since March 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to March 1, 2011.

On March 26, 2008, TEC purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. $181.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of June 30, 2012 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

Fair Value of Long-Term Debt

At June 30, 2012, total long-term debt had a carrying amount of $3,165.7 million and an estimated fair market value of $3,631.5 million. At Dec. 31, 2011, total long-term debt had a carrying amount of $3,075.8 million and an estimated fair market value of $3,435.3 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are level 2 instruments.

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and six months ended June 30, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended June 30,									Six months ended June 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2012
Unrealized (loss) gain on cash flow hedges	($	12.3	)	$	4.7		($	7.6	)	($	9.7	)	$	3.6		($	6.1	)
Reclassification from AOCI to net income		0.4			(0.2	)		0.2			0.3			(0.1	)		0.2
(Loss) Gain on cash flow hedges		(11.9	)		4.5			(7.4	)		(9.4	)		3.5			(5.9	)
Amortization of unrecognized benefit costs and other		0.8			(0.3	)		0.5			1.5			(0.9	)		0.6
Total other comprehensive (loss) income	($	11.1	)	$	4.2		($	6.9	)	($	7.9	)	$	2.6		($	5.3	)
2011
Unrealized (loss) gain on cash flow hedges	($	1.3	)	$	0.5		($	0.8	)	$	2.9		($	1.1	)	$	1.8
Reclassification from AOCI to net income		(0.9	)		0.3			(0.6	)		(1.4	)		0.5			(0.9	)
(Loss) Gain on cash flow hedges		(2.2	)		0.8			(1.4	)		1.5			(0.6	)		0.9
Amortization of unrecognized benefit costs and other		0.7			(0.3	)		0.4			1.3			(0.5	)		0.8
Total other comprehensive (loss) income	($	1.5	)	$	0.5		($	1.0	)	$	2.8		($	1.1	)	$	1.7

Accumulated Other Comprehensive Loss
(millions)	June 30, 2012			Dec. 31, 2011
Unrecognized pension losses and prior service credits(1)	($	30.6	)	($	31.2	)
Unrecognized other benefit gains, prior service costs and transition obligations(2)		14.2			14.2
Net unrealized losses from cash flow hedges(3)		(10.9	)		(5.0	)
Total accumulated other comprehensive loss	($	27.3	)	($	22.0	)

(1) Net of tax benefit of $18.8 million and $19.6 million as of June 30, 2012 and Dec. 31, 2011, respectively.

(2) Net of tax expense of $6.2 million and $6.2 million as of June 30, 2012 and Dec. 31, 2011, respectively.

(3) Net of tax benefit of $6.8 million and $3.2 million as of June 30, 2012 and Dec. 31, 2011, respectively.

16

9. Earnings Per Share

Earnings Per Share
	Three months ended June 30,						Six months ended June 30,
(millions, except per share amounts)	2012			2011			2012			2011
Basic earnings per share
Net income	$	73.1		$	77.6		$	123.7		$	129.3
Less: Income attributable to noncontrolling interest		0.0			(0.1	)		(0.1	)		(0.1	)
Less: Amount allocated to nonvested participating shareholders		(0.3	)		(0.4	)		(0.5	)		(0.7	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	72.8		$	77.1		$	123.1		$	128.5
Average common shares outstanding - Basic		214.3			213.6			214.1			213.3
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.34		$	0.36		$	0.58		$	0.60
Diluted earnings per share
Net income	$	73.1		$	77.6		$	123.7		$	129.3
Less: Income attributable to noncontrolling interest		0.0			(0.1	)		(0.1	)		(0.1	)
Less: Amount allocated to nonvested participating shareholders		(0.3	)		(0.4	)		(0.5	)		(0.7	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	72.8		$	77.1		$	123.1		$	128.5
Average common shares outstanding - Diluted		214.3			213.6			214.1			213.3
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		0.9			1.6			1.2			1.8
Average shares outstanding common - Diluted		215.2			215.2			215.3			215.1
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.34		$	0.36		$	0.57		$	0.60
Anti-dilutive shares		0.3			1.6			0.8			2.0

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 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, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

In 2004, Merco Group at Aventura Landings I, II and III (Merco) filed suit against PGS in Dade County Circuit Court alleging that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco was seeking damages for costs associated with the removal of such coal tar and from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS denied liability on the grounds that the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, PGS filed a counterclaim against Merco which claimed that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and, in June 2012, prior to receiving a ruling by the Judge, PGS and Merco settled the case, and PGS and Continental Holdings, Inc. agreed to a release for their claims against each other in the case. Both agreements have been approved by the court. The settlement is reflected as a regulatory asset at June 30, 2012 and is expected to be recovered through the regulatory process. The settlement did not impact the results of operations for the periods ended June 30, 2012 and is not material to the financial position of TEC or TECO Energy as of June 30, 2012.

17

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of June 30, 2012, TEC has estimated its ultimate financial liability to be $28.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in long-term “Regulatory liabilities” on the Consolidated Condensed Balance Sheets. 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 portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’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.

In instances where other PRPs are involved, many of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

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.

Potentially Responsible Party Notification

In October 2010, the EPA notified TEC that it is a PRP under the CERCLA for the proposed conduct of a contaminated soil removal action, if necessary, at a property owned by TEC in Tampa, Florida. The property owned by TEC is undeveloped except for the location of transmission lines and poles, and is adjacent to an industrial site, not owned by TEC, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to TEC’s ownership of the property described above but, to the knowledge of TEC, this assertion is not based upon any release of hazardous substances by TEC. TEC has been in contact with the EPA to resolve this matter, and on July 10, 2012, TEC received an Enforcement Action Memorandum from the EPA, outlining the remediation actions the EPA is requiring at the site. The estimated costs to remediate the site are not expected to be material to the financial results or financial position of TEC or TECO Energy. TEC expects the remediation to be substantially completed in the third quarter of 2012.

Environmental Protection Agency Administrative Order

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal, received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. TECO Coal responded to the EPA in February 2011, and has been in contact with the EPA to resolve this matter. The company is unable to estimate the possible loss or range of loss with respect to this matter due to the uncertainty regarding the scope and extent of TECO Coal’s potential liability, if any, and the costs of any required investigation and remediation related to these inactive mining operations.

18

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and TEC’s letters of credit and guarantees as of June 30, 2012 is as follows:

Guarantees - TECO Energy
(millions)					After(1)				Liabilities Recognized
Guarantees for the Benefit of:	2012		2013-2016		2016		Total		at June 30, 2012
TECO Coal
Fuel purchase related(2)	$	0.0	$	0.0	$	5.4	$	5.4	$	1.2
Other subsidiaries
Fuel purchase/energy management(2)		0.0		10.0		95.3		105.3		2.8
Total	$	0.0	$	10.0	$	100.7	$	110.7	$	4.0
Letters of Credit - Tampa Electric Company
(millions)					After(1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2012		2013-2016		2016		Total		at June 30, 2012
Tampa Electric(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2016.

(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 June 30, 2012. 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 and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At June 30, 2012, TECO Energy, TECO Finance, TEC 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.

19

Segment Information(1)
(millions) Three months ended June 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy
2012
Revenues - external	$	506.6	$	93.7	$	149.7	$	36.0	$	2.4		$	788.4
Sales to affiliates		0.2		1.1		0.0		0.0		(1.3	)		0.0
Total revenues		506.8		94.8		149.7		36.0		1.1			788.4
Depreciation and amortization		59.6		12.4		10.0		1.9		0.3			84.2
Total interest charges(1)		29.5		4.5		1.8		2.1		12.1			50.0
Internally allocated interest(1)		0.0		0.0		1.8		1.8		(3.6	)		0.0
Provision (benefit) for income taxes		31.9		5.7		4.1		3.4		(4.2	)		40.9
Net income (loss) attributable to TECO Energy	$	52.0	$	9.0	$	12.2	$	7.4	($	7.5	)	$	73.1
2011
Revenues - external	$	546.1	$	110.4	$	191.3	$	36.1	$	1.8		$	885.7
Sales to affiliates		0.4		0.8		0.0		0.0		(1.2	)		0.0
Total revenues		546.5		111.2		191.3		36.1		0.6			885.7
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		0.0		0.0			0.0
Depreciation and amortization		55.3		12.0		11.7		1.9		0.3			81.2
Total interest charges(1)		30.4		4.4		1.7		1.9		12.8			51.2
Internally allocated interest(1)		0.0		0.0		1.7		1.6		(3.3	)		0.0
Provision (benefit) for income taxes		36.9		3.7		5.0		3.3		(4.8	)		44.1
Net income (loss) attributable to TECO Energy	$	58.4	$	5.9	$	15.8	$	5.6	($	8.2	)	$	77.5
(millions)
Six months ended June 30,
2012
Revenues - external	$	952.9	$	203.7	$	288.1	$	68.9	$	4.8		$	1,518.4
Sales to affiliates		0.5		1.3		0.0		0.0		(1.8	)		0.0
Total revenues		953.4		205.0		288.1		68.9		3.0			1,518.4
Depreciation and amortization		117.0		25.0		20.8		3.7		0.7			167.2
Total interest charges(1)		59.5		8.9		3.6		4.2		24.2			100.4
Internally allocated interest(1)		0.0		0.0		3.5		3.6		(7.1	)		0.0
Provision (benefit) for income taxes		50.8		12.6		7.2		6.1		(9.2	)		67.5
Net income (loss) attributable to TECO Energy	$	83.4	$	20.0	$	22.0	$	14.0	($	15.8	)	$	123.6
2011
Revenues - external	$	979.0	$	264.6	$	365.0	$	69.7	$	3.5		$	1,681.8
Sales to affiliates		0.7		2.7		0.0		0.0		(3.4	)		0.0
Total revenues		979.7		267.3		365.0		69.7		0.1			1,681.8
Depreciation and amortization		110.2		23.8		22.6		3.7		0.7			161.0
Total interest charges(1)		61.3		8.9		3.4		3.8		26.4			103.8
Internally allocated interest(1)		0.0		0.0		3.3		3.1		(6.4	)		0.0
Provision (benefit) for income taxes		56.9		13.0		6.6		6.1		(10.1	)		72.5
Net income (loss) attributable to TECO Energy	$	90.0	$	20.6	$	24.0	$	11.9	($	17.3	)	$	129.2

20

(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy
At June 30, 2012
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	6,030.9	$	963.6	$	376.9	$	310.3	($	231.1	)	$	7,450.6
At Dec. 31, 2011
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,940.9	$	932.0	$	385.2	$	304.1	($	240.0	)	$	7,322.2

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2012 through June 2012 were at a pretax rate of 6.00% and for 2011 were at a pretax rate of 6.25% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

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.

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.

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 reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (seeNote 3).

A company’s physical contracts qualify for the 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 June 30, 2012, 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 June 30, 2012 and Dec. 31, 2011:

Total Derivatives(1)
(millions)	June 30, 2012		Dec. 31, 2011
Current assets	$	0.7	$	0.9
Long-term assets		0.1		0.0
Total assets	$	0.8	$	0.9
Current liabilities	$	40.5	$	58.4
Long-term liabilities		3.9		8.6
Total liabilities	$	44.4	$	67.0

(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.

21

The following table presents the derivative hedges of diesel fuel contracts at June 30, 2012 and Dec. 31, 2011 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	June 30, 2012		Dec. 31, 2011
Current assets	$	0.3	$	0.9
Long-term assets		0.0		0.0
Total assets	$	0.3	$	0.9
Current liabilities	$	1.6	$	0.0
Long-term liabilities		1.3		1.2
Total liabilities	$	2.9	$	1.2

The following table presents the derivative hedges of natural gas contracts at June 30, 2012 and Dec. 31, 2011 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)	June 30, 2012		Dec. 31, 2011
Current assets	$	0.4	$	0.0
Long-term assets		0.1		0.0
Total assets	$	0.5	$	0.0
Current liabilities	$	38.9	$	58.4
Long-term liabilities		2.6		7.4
Total liabilities	$	41.5	$	65.8

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at June 30, 2012 is a net loss of $10.9 million after tax and accumulated amortization. This compares to a net loss of $5.0 million in AOCI after tax and accumulated amortization at Dec. 31, 2011. The balance at June 30, 2012 is primarily comprised of interest rate swaps settled coincident with debt issued in June of 2008 and 2012 (seeNote 7). These amounts will be amortized into earnings over the life of the related debt.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2012:

Derivatives Designated As Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) at June 30, 2012	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.3	Derivative liabilities	$	1.6
Long-term	Derivative assets		0.0	Derivative liabilities		1.3
Natural gas derivatives:
Current	Derivative assets		0.4	Derivative liabilities		38.9
Long-term	Derivative assets		0.1	Derivative liabilities		2.6
Total derivatives designated as hedging instruments		$	0.8		$	44.4

22

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) atJune 30, 2012	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.4	Regulatory assets	$	38.9
Long-term	Regulatory liabilities		0.1	Regulatory assets		2.6
Total		$	0.5		$	41.5

(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 June 30, 2012, net pretax losses of $38.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

The following tables present the effect of hedging instruments on OCI and income for the three and six months ended June 30:

For the three months ended June 30: (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)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(2.7	)	Mining related costs		0.0
Total	($	7.6	)		($	0.2	)
2011
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.8	)	Mining related costs		0.8
Total	($	0.8	)		$	0.6

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

23

For the six months ended June 30: (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)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		(1.2	)	Mining related costs		0.2
Total	($	6.1	)		($	0.2	)
2011
Interest rate contracts	$	0.0		Interest expense	($	0.3	)
Commodity contracts:
Diesel fuel derivatives		1.8		Mining related costs		1.2
Total	$	1.8			$	0.9

(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 six months ended June 30, 2012 and 2011, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges and their effect on OCI and AOCI for the six months ended June 30:

For the six months ended June 30: (millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI(1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.4	)
Diesel fuel derivatives		(2.6	)		(1.2	)		0.2
Total	($	2.6	)	($	6.1	)	($	0.2	)
2011
Interest rate swaps	$	0.0		$	0.0		($	0.3	)
Diesel fuel derivatives		3.1			1.8			1.2
Total	$	3.1		$	1.8		$	0.9

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

24

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for both financial natural gas and financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of June 30, 2012, are expected to settle during the 2012, 2013 and 2014 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2012		0.0		4.9		0.0		20.1
2013		0.0		2.7		0.0		13.4
2014		0.0		1.5		0.0		2.1
Total		0.0		9.1		0.0		35.6

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 June 30, 2012, 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) EEI agreements - standardized power sales contracts in the electric industry; (2) ISDA agreements - standardized financial gas and electric contracts; and (3) NAESB agreements - 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 its counterparties and to consider nonperformance in valuing counterparty positions. The company monitors counterparties’ credit standings, 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 June 30, 2012, 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 TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’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 June 30, 2012:

Contingent Features
(millions) At June 30, 2012	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	44.0	)	($	44.0	)	$	0.0

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set 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 June 30, 2012 and Dec. 31, 2011. 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 and diesel fuel swaps, the market approach was used in determining fair value. There were no reclassifications between levels for the quarter.

25

Recurring Fair Value Measures
	At fair value as of June 30, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.5	$	0.0	$	0.5
Diesel fuel swaps		0.0		0.3		0.0		0.3
Total	$	0.0	$	0.8	$	0.0	$	0.8
Liabilities
Natural gas swaps	$	0.0	$	41.5	$	0.0	$	41.5
Diesel fuel swaps		0.0		2.9		0.0		2.9
Total	$	0.0	$	44.4	$	0.0	$	44.4

	At fair value as of Dec. 31, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Diesel fuel swaps		0.0		0.9		0.0		0.9
Total	$	0.0	$	0.9	$	0.0	$	0.9
Liabilities
Natural gas swaps	$	0.0	$	65.8	$	0.0	$	65.8
Diesel fuel swaps		0.0		1.2		0.0		1.2
Total	$	0.0	$	67.0	$	0.0	$	67.0

Natural gas and diesel fuel swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of these swaps are the 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 (seeNote 12).

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, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 30, 2012, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were liability positions.

26

14. Variable Interest Entities

The determination of a VIE’s 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.

TEC 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 117 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 VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC 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, TEC is not required to consolidate any of these entities. TEC purchased $20.8 million and $43.3 million pursuant to PPAs for the three and six months ended June 30, 2012, respectively, and $26.2 million and $42.0 million for the three and six months ended June 30, 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC 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, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $10.5 million and $25.2 million for the three and six months ended June 30, 2012, respectively, and $5.9 million and $13.0 million for the three and six months ended June 30, 2011, respectively, under this PPA.

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. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

15. Subsequent Events

Potentially Responsible Party Notification

In July 2012, TEC received an Enforcement Action Memorandum from the EPA in reference to the previously reported October 2010 EPA PRP notification. This memorandum outlines the remediation actions the EPA is requiring at the aforementioned site. The estimated costs to remediate the site are not expected to be material to the financial results or financial position of TEC or TECO Energy. TEC expects the remediation to be substantially completed in the third quarter of 2012. SeeNote 10for more information.

Wholesale and Transmission Rate Cases

In July 2012, the FERC approved the uncontested settlement that Tampa Electric filed with its customers in its wholesale requirements rate case earlier this year. The approved settlement will take effect in August and Tampa Electric will refund its wholesale requirements’ customers the appropriate amounts given the terms of the settlement. SeeNote 3for more information.

27

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 TEC as of June 30, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended June 30, 2012 and 2011. The results of operations for the three month and six month periods ended June 30, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012. References should be made to the explanatory notes affecting the consolidated financial statements contained in TEC’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 and to the notes on pages 36 through 48 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, June 30, 2012 and Dec. 31, 2011		29-30
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended June 30, 2012 and 2011		31-32
Consolidated Condensed Statements of Cash Flows for the six month periods ended June  30, 2012 and 2011		33
Notes to Consolidated Condensed Financial Statements		34-45

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

28

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	June 30, 2012			Dec. 31, 2011
Property, plant and equipment
Utility plant in service
Electric	$	6,603.8		$	6,516.0
Gas		1,140.8			1,113.5
Construction work in progress		271.9			239.2
Utility plant in service, at original costs		8,016.5			7,868.7
Accumulated depreciation		(2,318.8	)		(2,230.3	)
		5,697.7			5,638.4
Other property, net		6.5			6.5
Total property, plant and equipment, net		5,704.2			5,644.9
Current assets
Cash and cash equivalents		84.4			13.9
Receivables, less allowance for uncollectibles of $1.2 and $1.3 at June 30, 2012 and Dec. 31, 2011, respectively		241.9			216.8
Inventories, at average cost
Fuel		106.3			97.9
Materials and supplies		68.9			67.7
Regulatory assets		83.2			87.3
Derivative assets		0.4			0.0
Taxes receivable		0.0			14.6
Deferred income taxes		29.6			30.4
Prepayments and other current assets		18.7			10.5
Total current assets		633.4			539.1
Deferred debits
Unamortized debt expense		15.3			14.1
Regulatory assets		351.1			364.5
Derivative assets		0.1			0.0
Other		2.1			8.8
Total deferred debits		368.6			387.4
Total assets	$	6,706.2		$	6,571.4

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

29

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital	June 30,			Dec. 31,
(millions)	2012			2011
Capital
Common stock	$	1,852.4		$	1,852.4
Accumulated other comprehensive loss		(9.1	)		(4.6	)
Retained earnings		314.9			305.7
Total capital		2,158.2			2,153.5
Long-term debt, less amount due within one year		1,829.6			1,616.3
Total capital		3,987.8			3,769.8
Current liabilities
Long-term debt due within one year		256.4			374.9
Accounts payable		154.7			191.3
Customer deposits		161.4			159.5
Regulatory liabilities		83.4			86.2
Derivative liabilities		38.9			58.4
Interest accrued		29.1			25.6
Taxes accrued		46.4			11.9
Other		11.6			11.6
Total current liabilities		781.9			919.4
Deferred credits
Deferred income taxes		894.3			833.0
Investment tax credits		9.9			10.0
Derivative liabilities		2.6			7.4
Regulatory liabilities		654.1			647.8
Other		375.6			384.0
Total deferred credits		1,936.5			1,882.2
Commitments and Contingencies (see Note 8)
Total liabilities and capital	$	6,706.2		$	6,571.4

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

30

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended June 30,
(millions)	2012			2011
Revenues
Electric (includes franchise fees and gross receipts taxes of $23.4 in 2012 and $21.3 in 2011)	$	506.6		$	546.4
Gas (includes franchise fees and gross receipts taxes of $4.9 in 2012 and $5.8 in 2011)		93.8			110.4
Total revenues		600.4			656.8
Expenses
Operations
Fuel		167.9			194.2
Purchased power		31.2			43.9
Cost of natural gas sold		36.5			54.2
Other		85.6			82.0
Maintenance		28.6			31.6
Depreciation and amortization		72.0			67.3
Taxes, federal and state		37.5			40.4
Taxes, other than income		46.9			44.9
Total expenses		506.2			558.5
Income from operations		94.2			98.3
Other income
Allowance for other funds used during construction		0.5			0.3
Taxes, non-utility federal and state		(0.1	)		(0.2	)
Other income, net		0.4			0.7
Total other income		0.8			0.8
Interest charges
Interest on long-term debt		31.3			32.1
Other interest		3.0			2.8
Allowance for borrowed funds used during construction		(0.3	)		(0.1	)
Total interest charges		34.0			34.8
Net income		61.0			64.3
Other comprehensive income (loss), net of tax
Net unrealized (loss) gain on cash flow hedges		(4.7	)		0.2
Total other comprehensive (loss) income, net of tax		(4.7	)		0.2
Comprehensive income	$	56.3		$	64.5

31

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Six months ended June 30,
(millions)	2012			2011
Revenues
Electric (includes franchise fees and gross receipts taxes of $43.3 in 2012 and $40.6 in 2011)	$	953.2		$	979.4
Gas (includes franchise fees and gross receipts taxes of $11.1 in 2012 and $14.9 in 2011)		203.7			264.7
Total revenues		1,156.9			1,244.1
Expenses
Operations
Fuel		325.4			339.1
Purchased power		59.4			71.1
Cost of natural gas sold		78.1			136.2
Other		168.7			160.2
Maintenance		57.6			63.1
Depreciation and amortization		142.0			134.0
Taxes, federal and state		63.1			69.5
Taxes, other than income		92.3			91.5
Total expenses		986.6			1,064.7
Income from operations		170.3			179.4
Other income
Allowance for other funds used during construction		0.9			0.6
Taxes, non-utility federal and state		(0.3	)		(0.4	)
Other income, net		0.9			1.2
Total other income		1.5			1.4
Interest charges
Interest on long-term debt		63.0			64.8
Other interest		5.9			5.7
Allowance for borrowed funds used during construction		(0.5	)		(0.3	)
Total interest charges		68.4			70.2
Net income		103.4			110.6
Other comprehensive income (loss), net of tax
Net unrealized (loss) gain on cash flow hedges		(4.5	)		0.3
Total other comprehensive (loss) income, net of tax		(4.5	)		0.3
Comprehensive income	$	98.9		$	110.9

32

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended June 30,
(millions)	2012			2011
Cash flows from operating activities
Net income	$	103.4		$	110.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		142.0			134.0
Deferred income taxes		65.3			57.5
Investment tax credits, net		(0.1	)		(0.2	)
Allowance for funds used during construction		(0.9	)		(0.6	)
Deferred recovery clauses		(12.9	)		6.3
Receivables, less allowance for uncollectibles		(26.5	)		16.0
Inventories		(9.6	)		13.9
Prepayments		(8.2	)		(2.4	)
Taxes accrued		49.1			39.3
Interest accrued		3.5			5.2
Accounts payable		(17.3	)		(38.3	)
Gain on sale of assets, pretax		(0.2	)		(0.1	)
Other		5.7			15.2
Cash flows from operating activities		293.3			356.4
Cash flows from investing activities
Capital expenditures		(215.6	)		(166.3	)
Allowance for funds used during construction		0.9			0.6
Net proceeds from sale of assets		0.3			2.6
Cash flows used in investing activities		(214.4	)		(163.1	)
Cash flows from financing activities
Proceeds from long-term debt issuance		290.3			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(204.5	)		(75.3	)
Net (decrease) increase in short-term debt		0.0			(5.0	)
Dividends		(94.2	)		(105.8	)
Cash flows used in financing activities		(8.4	)		(186.1	)
Net increase in cash and cash equivalents		70.5			7.2
Cash and cash equivalents at beginning of period		13.9			3.7
Cash and cash equivalents at end of period	$	84.4		$	10.9

33

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2011 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. TEC 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. For the periods presented, no VIEs have been consolidated (seeNote 13).

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 TEC as of June 30, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended June 30, 2012 and 2011. The results of operations for the three and six month periods ended June 30, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. 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 U.S. GAAP.

Revenues

As of June 30, 2012 and Dec. 31, 2011, unbilled revenues of $54.1 million and $50.2 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 are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices 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. 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 amounts totaled $28.3 million and $54.4 million, respectively, for the three and six months ended June 30, 2012, compared to $27.1 million and $55.5 million, respectively, for the three and six months ended June 30, 2011.

Cash Flows Related to Derivatives and Hedging Activities

TEC 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

Offsetting Assets and Liabilities

In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. TEC will adopt this guidance as required. It will have no effect on TEC’s results of operations, financial 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 FERC under the 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 the PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations 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.

34

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $47.6 million and $43.6 million as of June 30, 2012 and Dec. 31, 2011, respectively.

Wholesale and Transmission Rate Cases

In July 2012, the FERC approved the uncontested settlement that Tampa Electric filed with its customers in its wholesale requirements rate case earlier this year. The approved settlement will take effect in August and Tampa Electric will refund its wholesale requirements’ customers the appropriate amounts given the terms of the settlement. Tampa Electric awaits FERC approval for its uncontested transmission rate case settlement, which was filed with FERC also earlier this year. The wholesale requirements and transmission rate case settlements’ rates will not have a material impact on Tampa Electric’s results.

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.

Details of the regulatory assets and liabilities as of June 30, 2012 and Dec. 31, 2011 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	June 30, 2012		Dec. 31, 2011
Regulatory assets:
Regulatory tax asset(1)	$	62.5	$	63.6
Other:
Cost-recovery clauses		58.6		73.3
Postretirement benefit asset		245.2		252.4
Deferred bond refinancing costs(2)		9.1		11.1
Environmental remediation		37.7		30.5
Competitive rate adjustment		3.5		3.5
Other		17.7		17.4
Total other regulatory assets		371.8		388.2
Total regulatory assets		434.3		451.8
Less: Current portion		83.2		87.3
Long-term regulatory assets	$	351.1	$	364.5
Regulatory liabilities:
Regulatory tax liability(1)	$	15.3	$	16.0
Other:
Cost-recovery clauses		58.7		61.4
Environmental remediation		28.4		28.4
Transmission and delivery storm reserve		47.6		43.6
Deferred gain on property sales(3)		4.1		5.0
Provision for stipulation and other		1.0		0.8
Accumulated reserve - cost of removal		582.4		578.8
Total other regulatory liabilities		722.2		718.0
Total regulatory liabilities		737.5		734.0
Less: Current portion		83.4		86.2
Long-term regulatory liabilities	$	654.1	$	647.8

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

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

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

35

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)	June 30, 2012		Dec 31, 2011
Clause recoverable(1)	$	62.1	$	76.8
Components of rate base(2)		258.5		264.9
Regulatory tax assets(3)		62.5		63.6
Capital structure and other(3)		51.2		46.5
Total	$	434.3	$	451.8

(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.

4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the three and six months ended June 30, 2012 and 2011 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of the company’s 2010 consolidated federal income tax return during 2011. The U.S. federal statute of limitations remains open for the year 2008 and forward. Years 2011 and 2012 are currently under examination by the IRS under the Compliance Assurance Program. 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 2012. 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 2008 and forward.

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found inNote 5,Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended June 30, 2012 and 2011, respectively, was $5.0 million and $3.1 million for pension benefits, and $3.1 million and $3.2 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2012 and 2011, respectively, was $9.2 million and $6.7 million for pension benefits, and $6.2 million and $6.7 million for other postretirement benefits.

For the fiscal 2012 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.797% for pension benefits under its qualified pension plan, and a discount rate of 4.744% for its other postretirement benefits as of their Jan. 1, 2012 measurement dates. Additionally, TECO Energy made contributions of $20.1 million to its pension plan in the six months ended June 30, 2012. TEC’s portion of the contributions was $15.7 million.

Included in the benefit expenses discussed above, for the three and six months ended June 30, 2012, TEC reclassed $3.8 million and $7.3 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

In July 2012, the President signed into law the Moving Ahead for Progress in the 21st Century Act (MAP-21). MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TEC is currently evaluating the impact MAP-21 will have on its pension contributions and on future PBGC premiums, and expects the required minimum pension contributions to be lower than the levels previously projected.

36

6. Short-Term Debt

At June 30, 2012 and Dec. 31, 2011, the following credit facilities and related borrowings existed:

Credit Facilities
	June 30, 2012						Dec. 31, 2011
(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(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	0.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	0.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Oct. 25, 2016.

At June 30, 2012, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. There were no outstanding borrowings at June 30, 2012 or Dec. 31, 2011.

Tampa Electric Company Accounts Receivable Facility

On Feb. 17, 2012, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 10 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 15, 2013, (ii) provides that TRC will pay program and liquidity fees, which will total 60 basis points, (iii) continues to provide 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 TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

7. Long-Term Debt

Issuance of Tampa Electric Company 4.10% Notes due 2042

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the Notes). The Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the Notes at its option 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. At any time on or after Dec. 15, 2041, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) and Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the HCIDA Bonds). On March 19, 2008, the HCIDA remarketed the HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the HCIDA Bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation.

On March 1, 2011, TEC purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously were in auction rate mode and were held by TEC since March 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to March 1, 2011.

37

On March 26, 2008, TEC purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. $181.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of June 30, 2012 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

Fair Value of Long-Term Debt

At June 30, 2012, TEC’s total long-term debt had a carrying amount of $2,087.7 million and an estimated fair market value of $2,422.3 million. At Dec. 31, 2011, total long-term debt had a carrying amount of $1,992.3 million and an estimated fair market value of $2,291.5 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are level 2 instruments.

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC 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 loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on TEC’s results of operations, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

In 2004, Merco Group at Aventura Landings I, II and III (Merco) filed suit against PGS in Dade County Circuit Court alleging that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco was seeking damages for costs associated with the removal of such coal tar and from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS denied liability on the grounds that the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, PGS filed a counterclaim against Merco which claimed that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and, in June 2012, prior to receiving a ruling by the Judge, PGS and Merco settled the case, and PGS and Continental Holdings, Inc. agreed to a release for their claims against each other in the case. Both agreements have been approved by the court. The settlement is reflected as a regulatory asset at June 30, 2012 and is expected to be recovered through the regulatory process. The settlement did not impact the results of operations for the periods ended June 30, 2012 and is not material to the financial position of TEC or TECO Energy as of June 30, 2012.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of June 30, 2012, TEC has estimated its ultimate financial liability to be $28.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in long-term “Regulatory liabilities” on TEC’s Consolidated Condensed Balance Sheets. 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 portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’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.

In instances where other PRPs are involved, many of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

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.

38

Potentially Responsible Party Notification

In October 2010, the EPA notified TEC that it is a PRP under the CERCLA for the proposed conduct of a contaminated soil removal action, if necessary, at a property owned by TEC in Tampa, Florida. The property owned by TEC is undeveloped except for the location of transmission lines and poles, and is adjacent to an industrial site, not owned by TEC, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to TEC’s ownership of the property described above but, to the knowledge of TEC, this assertion is not based upon any release of hazardous substances by TEC. TEC has been in contact with the EPA to resolve this matter, and on July 10, 2012, TEC received an Enforcement Action Memorandum from the EPA, outlining the remediation actions the EPA is requiring at the site. The estimated costs to remediate the site are not expected to be material to the financial results or financial position of TEC or TECO Energy. TEC expects the remediation to be substantially completed in the third quarter of 2012.

Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2012 are as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2012		2013-2016		After (1) 2016		Total		Liabilities Recognized at June 30, 2012
Tampa Electric(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2016.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at June 30, 2012. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2012, TEC was in compliance with all applicable financial covenants.

39

9. Segment Information

(millions) Three months ended June 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2012
Revenues - external	$	506.6	$	93.8	$	0.0		$	600.4
Sales to affiliates		0.2		1.0		(1.2	)		0.0
Total revenues		506.8		94.8		(1.2	)		600.4
Depreciation and amortization		59.6		12.4		0.0			72.0
Total interest charges		29.5		4.5		0.0			34.0
Provision for income taxes		31.9		5.7		0.0			37.6
Net income	$	52.0	$	9.0	$	0.0		$	61.0
2011
Revenues - external	$	546.4	$	110.4	$	0.0		$	656.8
Sales to affiliates		0.1		0.8		(0.9	)		0.0
Total revenues		546.5		111.2		(0.9	)		656.8
Depreciation and amortization		55.3		12.0		0.0			67.3
Total interest charges		30.4		4.4		0.0			34.8
Provision for income taxes		36.9		3.7		0.0			40.6
Net income	$	58.4	$	5.9	$	0.0		$	64.3
Six months ended June 30,
2012
Revenues - external	$	953.2	$	203.7	$	0.0		$	1,156.9
Sales to affiliates		0.2		1.3		(1.5	)		0.0
Total revenues		953.4		205.0		(1.5	)		1,156.9
Depreciation and amortization		117.0		25.0		0.0			142.0
Total interest charges		59.5		8.9		0.0			68.4
Provision for income taxes		50.9		12.6		0.0			63.5
Net income	$	83.4	$	20.0	$	0.0		$	103.4
Total assets at June 30, 2012	$	5,782.7	$	926.3	($	2.8	)	$	6,706.2
2011
Revenues - external	$	979.4	$	264.7	$	0.0		$	1,244.1
Sales to affiliates		0.3		2.6		(2.9	)		0.0
Total revenues		979.7		267.3		(2.9	)		1,244.1
Depreciation and amortization		110.2		23.8		0.0			134.0
Total interest charges		61.3		8.9		0.0			70.2
Provision for income taxes		56.9		13.0		0.0			69.9
Net income	$	90.0	$	20.6	$	0.0		$	110.6
Total assets at Dec. 31, 2011	$	5,693.0	$	888.4	($	10.0	)	$	6,571.4

10. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC 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.

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

40

The risk management policies adopted by TEC 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.

TEC 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 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.

TEC 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 reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (seeNote 3).

A company’s physical contracts qualify for the 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 June 30, 2012, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at June 30, 2012 and Dec. 31, 2011 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)	June 30, 2012		Dec. 31, 2011
Current assets	$	0.4	$	0.0
Long-term assets		0.1		0.0
Total assets	$	0.5	$	0.0
Current liabilities(1)	$	38.9	$	58.4
Long-term liabilities		2.6		7.4
Total liabilities	$	41.5	$	65.8

(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 AOCI related to previously settled interest rate swaps at June 30, 2012 is a net loss of $9.1 million after tax and accumulated amortization. This compares to a net loss of $4.6 million in AOCI after tax and accumulated amortization at Dec. 31, 2011. The balance at June 30, 2012 is comprised of interest rate swaps settled coincident with debt issued in June of 2008 and 2012 (seeNote 7). These amounts will be amortized into earnings over the life of the related debt.

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) at June 30, 2012	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.4	Regulatory assets	$	38.9
Long-term	Regulatory liabilities		0.1	Regulatory assets		2.6
Total		$	0.5		$	41.5

(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.

41

Based on the fair value of the instruments at June 30, 2012, net pretax losses of $38.5 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next 12 months.

The following table presents the effect of hedging instruments on OCI and income for the three and six months ended June 30:

(millions)	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)	Three months ended June  30:			Six months ended June 30:
2012
Interest rate contracts:	Interest expense	($	0.2	)	($	0.4	)
Total		($	0.2	)	($	0.4	)
2011
Interest rate contracts:	Interest expense	($	0.2	)	($	0.3	)
Total		($	0.2	)	($	0.3	)

(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 and six months ended June 30, 2012 and 2011, all hedges were effective.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of June 30, 2012, are expected to settle during the 2012, 2013 and 2014 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2012		0.0		20.1
2013		0.0		13.4
2014		0.0		2.1
Total		0.0		35.6

TEC 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. TEC 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 TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of June 30, 2012, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio are rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements - standardized power sales contracts in the electric industry; (2) ISDA agreements - standardized financial gas and electric contracts; and (3) NAESB agreements - standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance in valuing counterparty positions. TEC monitors counterparties’ credit standings, 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 TEC 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, TEC 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 June 30, 2012, all positions with counterparties are net liabilities.

42

Certain TEC derivative instruments contain provisions that require TEC’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. TEC 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 TEC’s derivative activity at June 30, 2012:

Contingent Features
(millions) At June 30, 2012	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	41.2	)	($	41.2	)	$	0.0

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and Dec. 31, 2011. 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. TEC’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. There were no reclassifications between levels for the quarter.

Recurring Derivative Fair Value Measures
	At fair value as of June 30, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.5	$	0.0	$	0.5
Total	$	0.0	$	0.5	$	0.0	$	0.5
Liabilities
Natural gas swaps	$	0.0	$	41.5	$	0.0	$	41.5
Total	$	0.0	$	41.5	$	0.0	$	41.5

	At fair value as of Dec. 31, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Total	$	0.0	$	0.0	$	0.0	$	0.0
Liabilities
Natural gas swaps	$	0.0	$	65.8	$	0.0	$	65.8
Total	$	0.0	$	65.8	$	0.0	$	65.8

Natural gas swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the 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 (seeNote 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At June 30, 2012, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions.

43

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended June 30,									Six months ended June 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2012
Unrealized loss on cash flow hedges	($	8.0	)	$	3.1		($	4.9	)	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		0.3			(0.1	)		0.2			0.6			(0.2	)		0.4
Loss on cash flow hedges		(7.7	)		3.0			(4.7	)		(7.4	)		2.9			(4.5	)
Total other comprehensive loss	($	7.7	)	$	3.0		($	4.7	)	($	7.4	)	$	2.9		($	4.5	)
2011
Unrealized gain on cash flow hedges	$	0.0		$	0.0		$	0.0		$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		0.3			(0.1	)		0.2			0.6			(0.3	)		0.3
Gain on cash flow hedges		0.3			(0.1	)		0.2			0.6			(0.3	)		0.3
Total other comprehensive income	$	0.3		($	0.1	)	$	0.2		$	0.6		($	0.3	)	$	0.3

Accumulated Other Comprehensive Loss
(millions)	June 30, 2012			Dec. 31, 2011
Net unrealized losses from cash flow hedges(1)	($	9.1	)	($	4.6	)
Total accumulated other comprehensive loss	($	9.1	)	($	4.6	)

(1) Net of tax benefit of $5.7 million and $2.9 million as of June 30, 2012 and Dec. 31, 2011, respectively.

13. Variable Interest Entities

The determination of a VIE’s 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.

TEC 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 117 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 VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC 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, TEC is not required to consolidate any of these entities. TEC purchased $20.8 million and $43.3 million pursuant to PPAs for the three and six months ended June 30, 2012, respectively, and $26.2 million and $42.0 million for the three and six months ended June 30, 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC 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, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $10.5 million and $25.2 million for the three and six months ended June 30, 2012, respectively, and $5.9 million and $13.0 million for the three and six months ended June 30, 2011, respectively, under this PPA.

TEC 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. In the normal course of business, TEC’s involvement with the remaining VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

44

14. Subsequent Events

Potentially Responsible Party Notification

In July 2012, TEC received an Enforcement Action Memorandum from the EPA in reference to the previously reported October 2010 EPA PRP notification. This memorandum outlines the remediation actions the EPA is requiring at the aforementioned site. The estimated costs to remediate the site are not expected to be material to the financial results or financial position of TEC or TECO Energy. TEC expects the remediation to be substantially completed in the third quarter of 2012. SeeNote 8for more information.

Wholesale and Transmission Rate Cases

In July 2012, the FERC approved the uncontested settlement that Tampa Electric filed with its customers in its wholesale requirements rate case earlier this year. The approved settlement will take effect in August and Tampa Electric will refund its wholesale requirements’ customers the appropriate amounts given the terms of the settlement. SeeNote 3for more information.

45

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 & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the 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; costs for alternative fuels used for power generation affecting demand for TECO Coal’s thermal coal 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 regulations 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 to complete the scheduled 2012 outage at the San José Power Station on time and on budget; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2011.

Earnings Summary- Unaudited
(millions, except per share amounts)	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
Consolidated revenues	$	788.4	$	885.7	$	1,518.4	$	1,681.8
Net income attributable to TECO Energy	$	73.1	$	77.5	$	123.6	$	129.2
Average common shares outstanding
Basic		214.3		213.6		214.1		213.3
Diluted		215.2		215.2		215.3		215.1
Earnings per share - basic	$	0.34	$	0.36	$	0.58	$	0.60
Earnings per share - diluted	$	0.34	$	0.36	$	0.57	$	0.60

Operating Results

Three Months Ended June 30, 2012

TECO Energy, Inc. reported second quarter net income of $73.1 million, or $0.34 per share, compared with $77.5 million, or $0.36 per share, in the second quarter of 2011.

Six Months Ended June 30, 2012

Year-to-date net income and earnings per share were $123.6 million, or $0.58 per share, in 2012, compared with $129.2 million, or $0.60 per share, in the same period in 2011.

Operating Company Results

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

46

Tampa Electric Company - Electric Division

Tampa Electric reported net income for the second quarter of $52.0 million, compared with $58.4 million for the same period in 2011. Results for the quarter reflected a 1.3% higher average number of customers, lower base revenues due to milder weather, higher depreciation and operations and maintenance expenses.

Total degree days in Tampa Electric’s service area in the second quarter of 2012 were 5% above normal, but 6% below the same period in 2011. Pretax base revenue was approximately $9.0 million lower than in 2011, primarily reflecting the wet and mild June weather after above-normal cooling degree days in April and May. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, decreased 2.3% in the second quarter of 2012 compared to the same period in 2011. The quarterly energy sales shown on the statistical summary that accompanies this earnings release reflect the energy sales based on the timing of billing cycles, which can vary period to period. Milder weather in the 2012 period reduced sales to residential customers. Energy sales to industrial-phosphate customers increased due to the transfer of certain load from self-generation to Tampa Electric’s system. Sales to commercial and other industrial customers increased due to improvements in the Florida economy.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, increased $1.6 million, reflecting lower generating system maintenance expenses and lower bad-debt expense more than offset by higher pension and other employee benefit expenses. Depreciation and amortization expense increased $2.7 million due to additions to facilities to serve customers.

Year-to-date net income was $83.4 million, compared with $90.0 million in the 2011 period, driven primarily by lower energy sales due to milder weather, partially offset by 1.1% higher average number of customers, and higher depreciation and operations and maintenance expenses.

Year-to-date total degree days in Tampa Electric’s service area were 7% above normal, but slightly below the prior year-to-date period, reflecting mild weather in January, February and June offset by above-normal cooling degree days in March, April and May. Pretax base revenue was $7 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather and voluntary conservation that typically occurs during periods without extreme weather.

In the 2012 year-to-date period, total net energy for load was essentially unchanged compared to the same period in 2011. Milder winter weather reduced sales to higher-margin residential customers, while sales to commercial and industrial customers were higher. Sales to interruptible industrial-phosphate customers increased due to the factors described above. Higher sales to commercial and industrial-other customers reflect the improvements in the Florida economy.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, increased $1.5 million reflecting the same factors as the second quarter. Compared to the 2011 year-to-date period, depreciation and amortization expense increased $4.2 million, reflecting additions to facilities to serve customers.

47

A summary of Tampa Electric’s operating statistics for the three and six months ended June 30, 2012 and 2011 follows:

	Operating Revenues								Kilowatt-hour sales
(millions, except average customers)	2012			2011		% Change			2012		2011		% Change
Three months ended June 30,
By Customer Type
Residential	$	248.7		$	249.9		(0.5	)		2,179.5		2,193.1		(0.6	)
Commercial		156.8			155.0		1.2			1,588.0		1,569.8		1.2
Industrial - Phosphate		18.8			15.5		21.3			225.8		182.2		23.9
Industrial - Other		26.3			25.4		3.5			284.8		274.5		3.8
Other sales of electricity		46.0			46.7		(1.5	)		458.3		462.7		(1.0	)
Deferred and other revenues(1)		(7.0	)		35.9		(119.5	)
		489.6			528.4		(7.3	)		4,736.4		4,682.3		1.2
Sales for resale		3.5			6.2		(43.5	)		52.8		85.0		(37.9	)
Other operating revenue		13.7			11.9		15.1
	$	506.8		$	546.5		(7.3	)		4,789.2		4,767.3		0.5
Average customers (thousands)		684.1			675.5		1.3
Retail net energy for load (kilowatt hours)										5,068.3		5,188.8		(2.3	)
Six months ended June 30,
By Customer Type
Residential	$	445.9		$	475.2		(6.2	)		3,904.6		4,167.0		(6.3	)
Commercial		296.7			293.8		1.0			2,981.9		2,961.0		0.7
Industrial - Phosphate		37.2			31.0		20.0			448.5		366.5		22.4
Industrial - Other		50.4			48.6		3.7			543.1		525.9		3.3
Other sales of electricity		88.7			89.8		(1.2	)		874.4		882.9		(1.0	)
Deferred and other revenues(1)		0.5			2.1		(76.2	)
		919.4			940.5		(2.2	)		8,752.5		8,903.3		(1.7	)
Sales for resale		6.7			12.5		(46.4	)		117.5		190.0		(38.2	)
Other operating revenue		27.3			26.7		2.2
	$	953.4		$	979.7		(2.7	)		8,870.0		9,093.3		(2.5	)
Average customers (thousands)		682.4			674.8		1.1
Retail net energy for load (kilowatt hours)										9,325.1		9,304.1		0.2

(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 $9.0 million for the second quarter, compared with $5.9 million in the same period in 2011. Quarterly results reflect a 1.2% higher average number of customers, higher sales to residential customers due to customer growth and increased sales volumes to commercial and interruptible industrial customers due to improved economic conditions. Non-fuel operations and maintenance expense decreased $2.5 million compared to the 2011 period, when operations and maintenance expenses included $2.1 million related to legal expenses associated with environmental contamination claims.

Peoples Gas reported net income of $20.0 million for the year-to-date period, compared with $20.6 million in the same period in 2011. Results reflect a 1.0% higher average number of customers, but lower usage by residential customers due to the unusually mild winter weather in the first quarter. Lower off-system sales volumes reflect the addition of new interstate pipeline capacity in 2011. Gas transported for power generation customers increased over the 2011 year-to-date period due to lower natural gas prices, which made it more economical to use natural gas for power generation. Non-fuel operations and maintenance expense decreased $1.7 million compared to the 2011 period, driven primarily by the same factors as in the second quarter.

48

A summary of PGS’s regulated operating statistics for the three and six months ended June 30, 2012 and 2011 follows:

	Operating Revenues							Therms
(millions, except average customers)	2012		2011		% Change			2012		2011		% Change
Three months ended June 30,
By Customer Type
Residential	$	28.3	$	28.6		(1.0	)		14.0		13.1		6.9
Commercial		32.1		32.4		(0.9	)		100.4		95.0		5.7
Industrial		2.2		2.1		4.8			57.7		49.4		16.8
Off system sales		18.9		33.4		(43.4	)		66.3		69.8		(5.0	)
Power generation		3.3		3.0		10.0			274.8		179.7		52.9
Other revenues		8.0		9.2		(13.0	)
	$	92.8	$	108.7		(14.6	)		513.2		407.0		26.1
By Sales Type
System supply	$	58.4	$	75.3		(22.4	)		89.1		93.1		(4.3	)
Transportation		26.4		24.2		9.1			424.1		313.9		35.1
Other revenues		8.0		9.2		(13.0	)
	$	92.8	$	108.7		(14.6	)		513.2		407.0		26.1
Average customers (thousands)		343.1		339.2		1.1
Six months ended June 30,
By Customer Type
Residential	$	68.9	$	84.7		(18.7	)		41.0		49.7		(17.5	)
Commercial		70.7		77.4		(8.7	)		218.9		217.4		0.7
Industrial		4.6		4.6		—			113.3		105.1		7.8
Off system sales		32.1		67.1		(52.2	)		110.3		142.5		(22.6	)
Power generation		6.7		5.5		21.8			483.4		296.0		63.3
Other revenues		18.1		22.8		(20.6	)
	$	201.1	$	262.1		(23.3	)		966.9		810.7		19.3
By Sales Type
System supply	$	126.9	$	186.2		(31.8	)		171.9		217.7		(21.0	)
Transportation		56.1		53.1		5.6			795.0		593.0		34.1
Other revenues		18.1		22.8		(20.6	)
	$	201.1	$	262.1		(23.3	)		966.9		810.7		19.3
Average customers (thousands)		342.6		339.0		1.1

TECO Coal

TECO Coal achieved second quarter net income of $12.2 million on sales of 1.6 million tons, compared with $15.8 million on sales of 2.1 million tons in the same period in 2011. Lower sales volumes in the 2012 quarter reflect the current coal market conditions and the timing of specialty coal shipments.

In 2012, second quarter results reflect an average net per-ton selling price, excluding transportation allowances, of slightly more than $94 per ton, almost 6% higher than in 2011, but below prior guidance due to a sales mix that was more heavily weighted to steam coal in the quarter due to the timing of metallurgical coal shipments. In the second quarter of 2012, the all-in total per-ton cost of production increased to slightly more than $84 per ton, which is below the middle of the cost guidance range previously provided. Compared with the 2011 period, the increased cost of production in the second quarter was driven by spreading fixed costs over fewer tons and higher surface mining costs due to increased diesel fuel usage as a result of trucking coal and overburden further due to the lack of new surface-mine permits. These factors were partially offset by reduced overtime and lower contract miner costs in 2012. TECO Coal’s effective income tax rate in the second quarter of 2012 was 25%, compared with 24% in the 2011 period.

TECO Coal recorded year-to-date net income of $22.0 million on sales of 3.0 million tons in 2012, compared with $24.0 million on sales of 4.1 million tons in the 2011 period. Lower sales volumes in the 2012 year-to-date period reflects the current coal market conditions. The 2012 year-to-date average net per-ton selling price was $95 per ton, compared with $85 per ton in 2011, and the all-in total per-ton cost of production was almost $86 per ton, compared with $78 per ton in 2011. In addition to the same cost factors as the second quarter, the 2012 year-to-date cost of production reflects costs incurred in the first quarter associated with idling a section of a mine and other costs associated with reducing production. TECO Coal’s effective income tax rate was 25%, compared with 22% in the 2011 year-to-date period.

49

TECO Guatemala

TECO Guatemala reported second quarter net income of $7.4 million in 2012, compared with $5.6 million in the 2011 period. Year-to-date 2012 net income was $14.0 million, compared with $11.9 million in the 2011 period. Results in the second quarter reflect higher contract and spot energy sales at the San José Power Station and lower operating expenses. Year-to-date results reflect lower contract and spot energy sales at the San José Power Station due to lower unit availability in the first quarter, but at higher prices than the 2011 period, and lower operating expenses.

Parent & other

The cost for Parent & other in the second quarter of 2012 was $7.5 million, compared with a cost of $8.2 million in the same period in 2011. The year-to-date Parent & other cost was $15.8 million in 2012, compared with $17.3 million in the 2011 period. Results for the 2012 quarter and year-to-date periods reflect lower interest expenses as a result of mid-year 2011 debt retirement, and higher earnings from the SeaCoast Gas Transmission LLC, which are recorded in Parent & other.

2012 Guidance and Business Drivers

Based on year-to-date actual results and expectations for the remainder of the year, TECO Energy is revising its 2012 earnings per share guidance to a range of $1.20 to $1.30, excluding charges and gains, and is updating its business drivers as discussed below.

Tampa Electric and Peoples Gas expect customer growth to continue to be in line with the trends experienced in the first half of 2012, and the forecast assumes normal weather for the remaining five months of the year. Based on the unfavorable effects of mild weather through July, Tampa Electric expects to earn near the bottom of its allowed return on equity range. Due to a new rate design implemented in its 2009 base rate proceeding, Peoples Gas is less weather sensitive and expects to earn near the middle of its allowed return on equity range.

TECO Coal now expects 2012 sales of between 6.0 million and 6.3 million tons at an average selling price across all products of about $96 per ton. The lower coal sales are driven primarily by an expectation that the unsold tons that were included in the previous sales forecast will not be sold. All of the expected 2012 sales are under contract. The selling price will average more than $97 per ton over the remainder of the year due to the timing of metallurgical coal shipments in the second half of the year. The 2012 product mix is now expected to be about 45% specialty coal, reflecting lower PCI coal sales. The cost of production is expected to remain within the previously provided cost range of $83 and $87 per ton as a result of cost-control efforts. TECO Coal’s effective income tax rate is expected to be about 25% for the full year.

The guidance assumes normal operations for the Alborada and San José power stations in Guatemala; however, the planned extended outage for a turbine rotor replacement at the San José Power Station, which is expected to reduce 2012 net income about $4 million compared with 2011, is scheduled for the fourth quarter.

This guidance is provided in the form of a range to allow for varying outcomes with respect to important variables, such as continuation of the current conditions in the Florida economy and housing markets, weather and customer usage at the Florida utilities, and the timing of contracted deliveries and production costs at TECO Coal.

Income Taxes

The provisions for income taxes from continuing operations for the six month periods ended June 30, 2012 and 2011 were $67.5 million and $72.5 million, respectively. The provision for income taxes in the six months ended Jun. 30, 2012 was impacted by lower operating income, decreased state income taxes, and decreased depletion at TECO Coal.

Liquidity and Capital Resources

The table below sets forth the June 30, 2012 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and Tampa Electric Company credit facilities.

Balances as of June 30, 2012
(millions)	Consolidated		Tampa Electric Company		Other		Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts / LCs		20.7		0.7		0.0		20.0
Available credit facilities		654.3		474.3		0.0		180.0
Cash and short-term investments		117.4		84.3		25.4		7.7
Total liquidity	$	771.7	$	558.6	$	25.4	$	187.7

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements (see the Credit Facilities section). In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At June 30, 2012, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at June 30, 2012. Reference is made to the specific agreements and instruments for more details.

50

Significant Financial Covenants
(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at June 30,  2012
TEC
Credit facility(2)	Debt/capital	Cannot exceed 65%	49.1%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%	49.1%
6.25% senior notes	Debt/capital Limit on liens(3)	Cannot exceed 60% Cannot exceed $700	49.1% $0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	Debt/capital	Cannot exceed 65%	57.6%
TECO Energy 6.75% notes and TECO Finance 6.75% notes	Restrictions on  secured Debt(4)	(5)	(5)

(1) As defined in each applicable instrument.

(2) SeeNote 6to theTECO Energy, Inc. Consolidated Condensed Financial Statements for a description of the credit facilities.

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

(4) These restrictions would not apply to first mortgage bonds of TEC if any were outstanding.

(5) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by principal property, capital stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes.

Credit Ratings of Senior Unsecured Debt at June 30, 2012
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	A3	A-
TECO Energy/TECO Finance	BBB	Baa2	BBB

On May 4, 2012, Moody’s upgraded the credit ratings of TEC, TECO Finance and TECO Energy to A3, Baa2 and Baa2, respectively, all with stable outlooks. All three credit rating agencies assign TEC, TECO Finance and TECO Energy investment grade ratings.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. The company’s access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of the company’s securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating. SeeNote 12 to theTECO Energy, Inc., Consolidated Condensed Financial Statements. The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect the company’s ability to borrow and may increase financing costs, which may decrease earnings. These credit ratings are not necessarily applicable to any particular security that the company may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of the company’s securities.

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.

Diesel fuel 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.

The valuation methods used to determine fair value are described inNotes 7 and 13 to theTECO 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 the company transacts have experienced dislocation. At June 30, 2012, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with all counterparties were liability positions.

51

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of critical accounting policies, seeTECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011.

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.

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 10% from Dec. 31, 2011 to June 30, 2012. For natural gas, the company maintained a similar volume hedged as of June 30, 2012 from Dec. 31, 2011.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the 6-month period ended June 30, 2012:

Changes in Fair Value of Derivatives(millions)
Net fair value of derivatives as of Dec. 31, 2011	$	(66.1	)
Additions and net changes in unrealized fair value of derivatives		(25.5	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		48.0
Net fair value of derivatives as of June 30, 2012	$	(43.6	)
Roll-Forward of Derivative Net Assets (Liabilities)(millions)
Total derivative net liabilities as of Dec. 31, 2011	$	(66.1	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(25.5	)
Recorded in earnings		0.0
Realized net settlement of derivatives		48.0
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of June 30, 2012	$	(43.6	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at June 30, 2012:

Maturity and Source of Derivative Contracts Net Assets (Liabilities)(millions)
Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	0.0		$	0.0		$	0.0
Other external sources(1)		(39.8	)		(3.8	)		(43.6	)
Model prices(2)		0.0			0.0			0.0
Total	$	(39.8	)	$	(3.8	)	$	(43.6	)

(1) Reflects over-the-counter natural gas or diesel fuel 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.

52

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.

TECO Energy is in the process of implementing an ERP system, developed by SAP, to replace certain of its legacy computer systems. This system became operational in July 2012 and the company is making appropriate changes to internal controls and procedures as the implementation progresses, as is expected with a major system implementation. Other than the changes required by the implementation of the SAP ERP system, none of which materially impair or significantly alter the effectiveness of the internal controls over financial reporting, there were no material changes in internal controls over financial reporting that occurred during the company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the effectiveness of our internal controls over financial reporting.

Tampa Electric Company

(a) Evaluation of Disclosure Controls and Procedures. TEC’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TEC’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, TEC’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, TEC’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. There was no change in TEC’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 TEC’s internal control over financial reporting that occurred during TEC’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

TEC is in the process of implementing an ERP system, developed by SAP, to replace certain of its legacy computer systems. This system became operational in July 2012 and TEC is making appropriate changes to internal controls and procedures as the implementation progresses, as is expected with a major system implementation. Other than the changes required by the implementation of the SAP ERP system, none of which materially impair or significantly alter the effectiveness of the internal controls over financial reporting, there were no material changes in internal controls over financial reporting that occurred during TEC’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the effectiveness of our internal controls over financial reporting.

53

PART II. OTHER INFORMATION

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

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

	(a)		(b)		(c)		(d)
	Total Number of Shares (or Units) Purchased (1)		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of  Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or  Units) that May Yet Be Purchased Under the Plans or Programs
Apr. 1, 2012 – Apr. 30, 2012		227,163	$	17.63		0.0	$	0.0
May 1, 2012 – May 31, 2012		7,585	$	17.54		0.0	$	0.0
June 1, 2012 – June 30, 2012		762	$	17.72		0.0	$	0.0
Total 2nd Quarter 2012		235,510	$	17.63		0.0	$	0.0

(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 4. MINE SAFETY INFORMATION

TECO Coal is subject to regulation by the Federal MSHA under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included inExhibit 95 to this quarterly report.

Item 6.EXHIBITS

Exhibits - See index on page 56.

54

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: August 3, 2012	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting and Chief Financial Officer
		(Chief Accounting Officer)
		(Principal Financial and Accounting Officer)
	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: August 3, 2012	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)

55

INDEX TO EXHIBITS

Exhibit No.	Description
3.1	Amended and Restated Articles of Incorporation of TECO Energy, Inc., as filed on May 3, 2012 (Exhibit 3.1, Form 8-K dated May 2, 2012 of TECO Energy, Inc.).	*
3.2	Bylaws of TECO Energy, Inc., as amended effective May 3, 2012 (Exhibit 3.2, Form 8-K dated May 2, 2012 of TECO Energy, Inc.).	*
3.3	Restated Articles of Incorporation of Tampa Electric Company, as amended on Nov. 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.4	Bylaws of Tampa Electric Company, as amended effective Feb. 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
4.1	Ninth Supplemental Indenture dated as of May 31, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee (including the form of 4.10% notes due 2042)(Exhibit 4.23, Form 8-K dated June 5, 2012).	*
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)
95	Mine Safety Disclosure
101.INS	XBRL Instance Document	*	*
101.SCH	XBRL Taxonomy Extension Schema Document	*	*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	*	*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*	*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document	*	*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	*	*

(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.

** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

56