Edgar Filing: TECO ENERGY INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2013

¨	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.	59-2052286
	(a Florida corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-1111

1-5007	TAMPA ELECTRIC COMPANY	59-0475140
	(a Florida corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-1111

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.

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.

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 26, 2013 was 217,310,055. As of July 26, 2013, 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 59

Index to Exhibits appears on page 58.

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
CAA		Federal Clean Air Act
capacity clause		capacity cost-recovery clause, as established by the FPSC
CMO		collateralized mortgage obligation
CO₂		carbon dioxide
CT		combustion turbine
DOE		U.S. Department of Energy
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
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
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
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
NMGC		New Mexico Gas Company, Inc., the principal subsidiary of NMGI
NMGI		New Mexico Gas Intermediate, Inc.
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
Tampa Electric		Tampa Electric, the electric division of Tampa Electric Company
TCAE		Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station
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.
TRC		TEC Receivables Company
VIE		variable interest entity
WRERA		The Worker, Retiree and Employer Recovery Act of 2008

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, 2013 and Dec. 31, 2012, and the results of their operations and cash flows for the periods ended June 30, 2013 and 2012. The results of operations for the three month and six month periods ended June 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013. 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, 2012 and to the notes on pages 11 through 28 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS


	Page No.

Consolidated Condensed Balance Sheets, June 30, 2013 and Dec. 31, 2012		5-6

Consolidated Condensed Statements of Income for the three month and six month periods ended June 30, 2013 and 2012		7-8

Consolidated Condensed Statements of Comprehensive Income for the three month and six month periods ended June 30, 2013 and 2012		9

Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2013 and 2012		10

Notes to Consolidated Condensed Financial Statements		11-28

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.

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited


*Assets*	June 30,			Dec. 31,
(millions)	2013			2012

Current assets
Cash and cash equivalents	$	153.3		$	200.5
Receivables, less allowance for uncollectibles of $4.2 at June 30, 2013 and Dec. 31, 2012, respectively		321.2			282.7
Inventories, at average cost
Fuel		143.6			123.6
Materials and supplies		81.8			82.1
Derivative assets		0.1			0.0
Regulatory assets		47.4			70.3
Deferred income taxes		25.6			63.3
Prepayments and other current assets		38.2			33.9
Income tax receivables		0.8			0.4

Total current assets		812.0			856.8


Property, plant and equipment
Utility plant in service
Electric		6,814.4			6,655.8
Gas		1,275.2			1,228.3
Construction work in progress		319.6			336.1
Other property		445.4			443.8

Property, plant and equipment, at original costs		8,854.6			8,664.0
Accumulated depreciation		(2,814.1	)		(2,695.5	)

Total property, plant and equipment, net		6,040.5			5,968.5


Other assets
Regulatory assets		374.1			382.6
Derivative assets		0.0			0.2
Deferred charges and other assets		127.7			126.8

Total other assets		501.8			509.6

Total assets	$	7,354.3		$	7,334.9

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

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited


*Liabilities and Capital*	June 30,			Dec. 31,
(millions)	2013			2012

Current liabilities
Long-term debt due within one year	$	83.3		$	0.0
Accounts payable		240.3			232.8
Customer deposits		164.1			162.9
Regulatory liabilities		84.9			105.6
Derivative liabilities		6.8			14.6
Interest accrued		35.2			33.2
Taxes accrued		63.4			32.1
Other		20.0			19.9

Total current liabilities		698.0			601.1


Other liabilities
Deferred income taxes		295.7			277.9
Investment tax credits		9.5			9.7
Regulatory liabilities		627.3			631.4
Derivative liabilities		1.3			0.6
Deferred credits and other liabilities		532.6			549.7
Long-term debt, less amount due within one year		2,889.4			2,972.7

Total other liabilities		4,355.8			4,442.0


Commitments and contingencies (see Note 10)

Capital
Common equity (400.0 million shares authorized; par value $1; 217.3 million and 216.6 million shares outstanding at June 30, 2013 and Dec. 31, 2012, respectively)		217.3			216.6
Additional paid in capital		1,573.4			1,564.5
Retained earnings		539.1			541.7
Accumulated other comprehensive loss		(29.3	)		(31.0	)

Total capital		2,300.5			2,291.8

Total liabilities and capital	$	7,354.3		$	7,334.9

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

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited


		Three months ended June 30,
(millions, except per share amounts)		2013			2012
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $26.7 in 2013 and $28.3 in 2012)		$	604.0		$	600.3
Unregulated			131.9			152.2

Total revenues			735.9			752.5

Expenses
Regulated operations and maintenance
Fuel			174.5			167.9
Purchased power			20.5			31.2
Cost of natural gas sold			40.7			36.4
Other			129.6			114.6
Operation and maintenance other expense
Mining related costs			110.2			113.3
Other			3.4			1.2
Depreciation and amortization			83.9			82.3
Taxes, other than income			53.6			56.5

Total expenses			616.4			603.4

Income from continuing operations			119.5			149.1

Other income
Allowance for other funds used during construction			1.4			0.5
Other income			1.6			1.3

Total other income			3.0			1.8

Interest charges
Interest expense			43.5			48.2
Allowance for borrowed funds used during construction			(0.8	)		(0.3	)

Total interest charges			42.7			47.9

Income from continuing operations before provision for income taxes			79.8			103.0
Provision for income taxes			28.2			37.4

Net income from continuing operations			51.6			65.6

Discontinued operations
(Loss) Income from discontinued operations			(0.2	)		11.1
Provision for income taxes			0.0			3.5

(Loss) Income from discontinued operations, net			(0.2	)		7.6
Less: Income from discontinued operations attributable to noncontrolling interest			0.0			0.1

(Loss) Income from discontinued operations attributable to TECO Energy, net			(0.2	)		7.5

Net income attributable to TECO Energy		$	51.4		$	73.1

Average common shares outstanding	– Basic		215.0			214.3
	– Diluted		215.5			215.2

Earnings per share from continuing operations	– Basic	$	0.24		$	0.30
	– Diluted	$	0.24		$	0.30

Earnings per share from discontinued operations	– Basic	$	0.00		$	0.04
	– Diluted	$	0.00		$	0.04

Earnings per share attributable to TECO Energy	– Basic	$	0.24		$	0.34
	– Diluted	$	0.24		$	0.34

Dividends paid per common share outstanding		$	0.22		$	0.22

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

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited


		Six months ended June 30,
(millions, except per share amounts)		2013			2012
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $52.1 in 2013 and $54.4 in 2012)		$	1,143.1		$	1,156.7
Unregulated			253.9			292.9

Total revenues			1,397.0			1,449.6

Expenses
Regulated operations and maintenance
Fuel			314.5			325.4
Purchased power			35.1			59.4
Cost of natural gas sold			90.2			78.0
Other			250.4			226.8
Operation and maintenance other expense
Mining related costs			205.7			217.2
Other			4.7			2.9
Depreciation and amortization			165.9			163.5
Taxes, other than income			106.9			112.5

Total expenses			1,173.4			1,185.7

Income from continuing operations			223.6			263.9

Other income
Allowance for other funds used during construction			2.5			0.9
Other income			3.2			3.1

Total other income			5.7			4.0

Interest charges
Interest expense			86.5			96.7
Allowance for borrowed funds used during construction			(1.4	)		(0.5	)

Total interest charges			85.1			96.2

Income from continuing operations before provision for income taxes			144.2			171.7
Provision for income taxes			51.4			61.5

Net income from continuing operations			92.8			110.2

Discontinued operations
Income from discontinued operations			0.2			19.5
Provision for income taxes			0.1			5.9

Income from discontinued operations, net			0.1			13.6
Less: Income from discontinued operations attributable to noncontrolling interest			0.0			0.2

Income from discontinued operations attributable to TECO Energy, net			0.1			13.4

Net income attributable to TECO Energy		$	92.9		$	123.6

Average common shares outstanding	– Basic		214.8			214.1
	– Diluted		215.3			215.3

Earnings per share from continuing operations	– Basic	$	0.43		$	0.51
	– Diluted	$	0.43		$	0.50

Earnings per share from discontinued operations	– Basic	$	0.00		$	0.07
	– Diluted	$	0.00		$	0.07

Earnings per share attributable to TECO Energy	– Basic	$	0.43		$	0.58
	– Diluted	$	0.43		$	0.57

Dividends paid per common share outstanding		$	0.44		$	0.44

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

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited


	Three months ended June 30,						Six months ended June 30,
(millions)	2013			2012			2013		2012
Net income attributable to TECO Energy	$	51.4		$	73.1		$	92.9	$	123.6

Other comprehensive income, net of tax
Net unrealized gains (loss) on cash flow hedges		(0.1	)		(7.4	)		0.3		(5.9	)
Amortization of unrecognized benefit costs		0.7			0.5			1.4		0.6

Other comprehensive income (loss), net of tax		0.6			(6.9	)		1.7		(5.3	)

Comprehensive income attributable to TECO Energy	$	52.0		$	66.2		$	94.6	$	118.3

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

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited


	Six months ended June 30,
(millions)	2013			2012
Cash flows from operating activities
Net income attributable to TECO Energy	$	92.9		$	123.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		165.9			167.2
Deferred income taxes		52.1			63.4
Investment tax credits		(0.2	)		(0.1	)
Allowance for other funds used during construction		(2.5	)		(0.9	)
Non-cash stock compensation		6.9			5.3
Gain on sales of business/assets, pretax		(0.2	)		(0.1	)
Deferred recovery clauses		(5.9	)		(12.9	)
Receivables, less allowance for uncollectibles		(38.5	)		(2.8	)
Inventories		(19.7	)		(30.8	)
Prepayments and other current assets		(4.3	)		(11.6	)
Taxes accrued		28.1			31.3
Interest accrued		2.0			3.5
Accounts payable		13.0			(26.9	)
Other		(1.8	)		(2.8	)

Cash flows from operating activities		287.8			305.4

Cash flows from investing activities
Capital expenditures		(249.6	)		(240.9	)
Allowance for other funds used during construction		2.5			0.9
Net proceeds from sales of business/assets		0.3			0.0

Cash flows used in investing activities		(246.8	)		(240.0	)

Cash flows from financing activities
Dividends		(95.6	)		(95.1	)
Proceeds from the sale of common stock		7.4			3.2
Proceeds from long-term debt issuance		0.0			290.3
Repayment of long-term debt/Purchase in lieu of redemption		0.0			(210.1	)
Dividends to noncontrolling interest		0.0			(0.3	)
Net increase in short-term debt		0.0			20.0

Cash flows (used in) from financing activities		(88.2	)		8.0

Net (decrease) increase in cash and cash equivalents		(47.2	)		73.4
Cash and cash equivalents at beginning of the period		200.5			44.0

Cash and cash equivalents at end of the period	$	153.3		$	117.4

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

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See the company’s 2012 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 in continuing operations (see Note 14).

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 TECO Energy, Inc. and its subsidiaries as of June 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended June 30, 2013 and 2012. The results of operations for the three and six months ended June 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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, 2013 and Dec. 31, 2012, unbilled revenues of $55.8 million and $49.0 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 $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013, compared to $28.3 million and $54.4 million, respectively, for the three and six months ended June 30, 2012.

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.

Reclassifications

Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TECO Energy’s net income in any period.

2. New Accounting Pronouncements

Unrecognized Tax Benefits

In July 2013, the FASB issued guidance regarding the presentation of unrecognized tax benefits in the statement of position when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. It requires that an unrecognized tax benefit be presented as a reduction to a deferred tax asset for net operating loss carryforwards, similar tax losses

or tax credit carryforwards, with certain exceptions. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. The guidance will have no effect on the company’s results of operations, financial position or cash flows.

Comprehensive Income

In February 2013, the FASB issued guidance requiring improved disclosures of significant reclassifications out of AOCI and their corresponding effect on net income. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2012. The company has adopted this guidance as required. It has 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 is also subject to regulation by the FERC under PUHCA 2005. However, pursuant to a waiver granted in accordance with the FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the 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.

Base Rates-Tampa Electric

Tampa Electric’s 2013 and 2012 results reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

On Feb. 4, 2013, Tampa Electric delivered a letter to the FPSC notifying it of its intent to file a request for an increase in its retail base rates and service charges. On April 5, 2013, Tampa Electric filed a petition with the FPSC requesting, among other things, a permanent increase in rates and service charges sufficient to generate additional annual revenues of approximately $134.8 million, to be effective on or after Jan. 1, 2014. The request provides for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requests certain changes to existing rate schedules, as well as the adoption of new rate designs.

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 $53.4 million and $50.4 million as of June 30, 2013 and Dec. 31, 2012, respectively.

Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period in which 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, 2013 and Dec. 31, 2012 are presented in the following table:


Regulatory Assets and Liabilities
(millions)	June 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	67.0	$	67.2

Other:
Cost-recovery clauses		21.0		42.9
Postretirement benefit asset		267.9		276.1
Deferred bond refinancing costs ⁽²⁾		8.6		9.2
Environmental remediation		47.1		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5

Total other regulatory assets		354.5		385.7

Total regulatory assets		421.5		452.9
Less: Current portion		47.4		70.3

Long-term regulatory assets	$	374.1	$	382.6

Regulatory liabilities:
Regulatory tax liability ⁽¹⁾	$	13.9	$	14.6

Other:
Cost-recovery clauses		53.2		73.9
Transmission and delivery storm reserve		53.4		50.4
Deferred gain on property sales ⁽³⁾		2.7		3.4
Provision for stipulation and other		1.1		1.0
Accumulated reserve - cost of removal		587.9		593.7

Total other regulatory liabilities		698.3		722.4

Total regulatory liabilities		712.2		737.0
Less: Current portion		84.9		105.6

Long-term regulatory liabilities	$	627.3	$	631.4

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

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

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

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


Regulatory Assets
(millions)	June 30, 2013		Dec. 31, 2012
Clause recoverable ⁽¹⁾	$	25.2	$	47.0
Components of rate base ⁽²⁾		270.7		279.1
Regulatory tax assets ⁽³⁾		67.0		67.2
Capital structure and other ⁽³⁾		58.6		59.6

Total	$	421.5	$	452.9

(1)	To be recovered through recovery mechanisms 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 subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2011 consolidated federal income tax return during 2012. The U.S. federal statute of limitations remains open for years 2009 and forward. Years 2012 and 2013 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 2013. U.S. state jurisdictions have statutes of limitations generally ranging from three to four 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 2009 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, 2013, the company recorded $0.1 million of pretax charges for interest only.

The effective tax rate decreased to 35.64% for the six months ended June 30, 2013 from 35.82% for the same period in 2012. The slight decrease is principally due to state income taxes.

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,	2013			2012			2013			2012
Components of net periodic benefit expense
Service cost	$	4.3		$	4.1		$	0.5		$	0.5
Interest cost on projected benefit obligations		7.2			7.6			2.4			2.6
Expected return on assets		(9.5	)		(8.9	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			0.5
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		0.2
Actuarial loss		5.3			3.9			0.2			0.0

Net pension expense recognized in the Consolidated Condensed Statements of Income	$	7.2		$	6.6		$	3.0		$	3.8


Six months ended June 30,
Components of net periodic benefit expense
Service cost	$	9.1		$	8.5		$	1.2		$	1.2
Interest cost on projected benefit obligations		14.4			15.0			4.7			5.1
Expected return on assets		(19.2	)		(18.5	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			0.9
Prior service (benefit) cost		(0.2	)		(0.2	)		(0.2	)		0.4
Actuarial loss		10.3			7.6			0.5			0.0

Net pension expense recognized in the Consolidated Condensed Statements of Income	$	14.4		$	12.4		$	6.2		$	7.6

For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. Additionally, TECO Energy made contributions of $23.8 million to its pension plan for the six months ended June 30, 2013.

For the three and six months ended June 30, 2013, TECO Energy and its subsidiaries reclassed $1.1 million and $2.2 million pretax, 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, 2013, TEC reclassed $4.2 million and $8.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

6. Short-Term Debt

At June 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:


Credit Facilities
	June 30, 2013						Dec. 31, 2012
(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	$	1.5	$	325.0	$	0.0	$	1.5
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		0.0		0.0		200.0		0.0		0.0

Total	$	675.0	$	0.0	$	1.5	$	675.0	$	0.0	$	1.5

(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, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at June 30, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 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. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 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.

Amendment of TECO Energy/TECO Finance Credit Facility

On June 24, 2013, TECO Energy and TECO Finance entered into an Amendment No. 1 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011 (TECO Credit Facility). Pursuant to the TECO Credit Facility, TECO Finance may borrow up to $200 million from time to time on a revolving basis. The TECO Credit Facility matures on Oct. 25, 2016.

The Amendment was entered into to accommodate the acquisition of NMGI, as described in Note 16 herein by (i) temporarily changing the total debt-to-total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closes, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the normal capitalization ratio of 0.65 to 1.00 and (ii) changing the definition of Permitted Liens as defined in the TECO Credit Facility to permit the acquisition of a significant subsidiary that carries secured debt and making other changes matching the corresponding covenant in the Bridge Facility, as described in Note 16 herein. More specifically, the Amendment adds to the definition of Permitted Liens, (i) liens existing on any property or asset prior to the acquisition thereof by any significant subsidiary or existing on any property or assets of any person that becomes a significant subsidiary after the date of the Amendment prior to the time such person becomes a significant subsidiary, (ii) liens on assets subject to existing liens to secure additional obligations and (iii) mortgage bonds issued by certain regulated significant subsidiaries including NMGC in a principal amount not exceeding 66 2/3% of the value of such significant subsidiary’s plant, property and equipment. The Amendment also contains other minor changes to the TECO Credit Facility.

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2013, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,331.8 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,439.4 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, 2013 and 2012, 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
2013
Unrealized (loss) gain on cash flow hedges	$	(0.7	)	$	0.3		$	(0.4	)	$	(0.4	)	$	0.2		$	(0.2	)
Reclassification from AOCI to net income ⁽¹⁾		0.5			(0.2	)		0.3			0.8			(0.3	)		0.5

(Loss) Gain on cash flow hedges		(0.2	)		0.1			(0.1	)		0.4			(0.1	)		0.3
Amortization of unrecognized benefit costs ⁽²⁾		1.1			(0.4	)		0.7			2.2			(0.8	)		1.4

Total other comprehensive (loss) income	$	0.9		$	(0.3	)	$	0.6		$	2.6		$	(0.9	)	$	1.7

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 ⁽¹⁾		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 ⁽²⁾		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	)

(1)	Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Mining related costs.

(2)	Related to postretirement benefits. See Note 5 for additional information.


Accumulated Other Comprehensive (Loss) Income
(millions)	June 30, 2013			Dec. 31, 2012
Unrecognized pension loss and prior service (benefit) credit ⁽¹⁾	$	(31.5	)	$	(32.9	)
Unrecognized other benefit loss, prior service (benefit) cost and transition obligation ⁽²⁾		11.1			11.1
Net unrealized losses from cash flow hedges ⁽³⁾		(8.9	)		(9.2	)

Total accumulated other comprehensive loss	$	(29.3	)	$	(31.0	)

(1)	Net of tax benefit of $19.3 million and $20.1 million as of June 30, 2013 and Dec. 31, 2012, respectively.

(2)	Net of tax expense of $6.7 million and $6.7 million as of June 30, 2013 and Dec. 31, 2012, respectively.

(3)	Net of tax benefit of $5.6 million and $5.8 million as of June 30, 2013 and Dec. 31, 2012, respectively.

9. Earnings Per Share


	For the three months ended June 30,						For the six months ended June 30,
(millions, except per share amounts)	2013 ⁽¹⁾			2012 ⁽¹⁾			2013 ⁽¹⁾			2012 ⁽¹⁾
Basic earnings per share
Net income from continuing operations	$	51.6		$	65.6		$	92.8		$	110.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.3	)		(0.4	)

Income before discontinued operations available to common shareholders - Basic	$	51.4		$	65.4		$	92.5		$	109.8

(Loss) Income from discontinued operations attributable to TECO Energy, net	$	(0.2	)	$	7.5		$	0.1		$	13.4
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0

(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	(0.2	)	$	7.5		$	0.1		$	13.4

Net income attributable to TECO Energy	$	51.4		$	73.1		$	92.9		$	123.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.3	)		(0.4	)

Net income attributable to TECO Energy available to common shareholders - Basic	$	51.2		$	72.9		$	92.6		$	123.2

Average common shares outstanding - Basic		215.0			214.3			214.8			214.1

Earnings per share from continuing operations available to common shareholders - Basic	$	0.24		$	0.30		$	0.43		$	0.51

Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		$	0.04		$	0.00		$	0.07

Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.24		$	0.34		$	0.43		$	0.58


Diluted earnings per share
Net income from continuing operations	$	51.6		$	65.6		$	92.8		$	110.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.3	)		(0.4	)

Income before discontinued operations available to common shareholders - Diluted	$	51.4		$	65.4		$	92.5		$	109.8

(Loss) Income from discontinued operations attributable to TECO Energy, net	$	(0.2	)	$	7.5		$	0.1		$	13.4
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0

(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	(0.2	)	$	7.5		$	0.1		$	13.4

Net income attributable to TECO Energy	$	51.4		$	73.1		$	92.9		$	123.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.3	)		(0.4	)

Net income attributable to TECO Energy available to common shareholders - Diluted	$	51.2		$	72.9		$	92.6		$	123.2

Unadjusted average common shares outstanding - Diluted		215.0			214.3			214.8			214.1
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.9			0.5			1.2

Average common shares outstanding - Diluted		215.5			215.2			215.3			215.3

Earnings per share from continuing operations available to common shareholders - Diluted	$	0.24		$	0.30		$	0.43		$	0.50

Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		$	0.04		$	0.00		$	0.07

Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.24		$	0.34		$	0.43		$	0.57

Anti-dilutive shares		0.0			0.3			0.0			0.8

(1)	Periods presented reflect the classification of TECO Guatemala as discontinued operations (see Note 15).

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.

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. Two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim and the plaintiffs have filed for reconsideration of the ruling. PGS’s suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident remains pending, as does the Posen Construction counter-claim against PGS alleging negligence. In addition, the suit filed by the Posen Construction employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees are maintaining a suit against TEC in Hillsborough County Circuit Court, Florida for personal injuries allegedly caused by exposure to a chemical substance at one of TEC’s power stations. The suit was originally filed in 2002 and recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected in the first half of 2014.

The company believes the claims in each of the pending actions described above in this item are without merit and intends to defend each matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters.

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, 2013, TEC has estimated its ultimate financial liability to be $37.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” 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, most 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. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Environmental Protection Agency 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) (the “114 Letter”) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station in Polk County, Florida with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter. TEC responded with the requested information on Apr. 26, 2013 and has not received any response from the EPA on this matter.

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. A consent agreement and final order with the EPA with respect to this matter became effective in July 2013, the costs associated with which were not material to the financial results or financial position of TECO Energy.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of June 30, 2013 is as follows:


Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2013		2014-2017		After⁽¹⁾ 2017		Total		Liabilities Recognized at June 30, 2013
TECO Coal
Fuel purchase related ⁽²⁾	$	0.0	$	1.4	$	4.0	$	5.4	$	2.0
Other subsidiaries
Guaranty under sale agreement⁽³⁾		0.0		4.9		0.0		4.9		4.9
Fuel purchase/energy management ⁽²⁾		0.0		10.0		94.3		104.3		1.1

Total	$	0.0	$	16.3	$	98.3	$	114.6	$	8.0


Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After⁽¹⁾ 2017		Total		Liabilities Recognized at June 30, 2013
Tampa Electric ⁽²⁾	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

(1)	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2017.

(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, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3)	The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement of the TECO Guatemala equity interests.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, 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, 2013, 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.


Segment Information ⁽¹⁾
(millions)	Tampa		Peoples		TECO			TECO		Other &			TECO
Three months ended June 30,	Electric		Gas		Coal			Guatemala⁽²⁾		Eliminations			Energy
2013
Revenues - external	$	502.6	$	101.3	$	128.4		$	0.0	$	3.6		$	735.9
Sales to affiliates		0.3		0.5		0.0			0.0		(0.8	)		0.0

Total revenues		502.9		101.8		128.4			0.0		2.8			735.9
Depreciation and amortization		60.8		13.2		9.5			0.0		0.4			83.9
Total interest charges ⁽¹⁾		23.3		3.3		1.7			0.0		14.4			42.7
Internally allocated interest ⁽¹⁾		0.0		0.0		1.7			0.0		(1.7	)		0.0
Provision (benefit) for income taxes		31.5		5.0		(0.9	)		0.0		(7.4	)		28.2
Net income from continuing operations		50.6		7.9		0.7			0.0		(7.6	)		51.6
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0		(0.2	)		(0.2	)
Net income attributable to TECO Energy	$	50.6	$	7.9	$	0.7		$	0.0	$	(7.8	)	$	51.4

2012
Revenues - external	$	506.6	$	93.7	$	149.7		$	0.0	$	2.5		$	752.5
Sales to affiliates		0.2		1.1		0.0			0.0		(1.3	)		0.0

Total revenues		506.8		94.8		149.7			0.0		1.2			752.5
Depreciation and amortization		59.6		12.4		10.0			0.0		0.3			82.3
Total interest charges ⁽¹⁾		29.5		4.5		1.8			0.0		12.1			47.9
Internally allocated interest ⁽¹⁾		0.0		0.0		1.8			0.0		(1.8	)		0.0
Provision (benefit) for income taxes		31.9		5.7		4.1			0.0		(4.3	)		37.4
Net income from continuing operations		52.0		9.0		12.2			0.0		(7.6	)		65.6
Income from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			7.4		0.1			7.5
Net income attributable to TECO Energy	$	52.0	$	9.0	$	12.2		$	7.4	$	(7.5	)	$	73.1


(millions)
Six months ended June 30,
2013
Revenues - external	$	920.4	$	223.2	$	246.3		$	0.0	$	7.1		$	1,397.0
Sales to affiliates		0.5		0.5		0.0			0.0		(1.0	)		0.0

Total revenues		920.9		223.7		246.3			0.0		6.1			1,397.0
Depreciation and amortization		119.8		26.2		19.2			0.0		0.7			165.9
Total interest charges ⁽¹⁾		46.7		6.7		3.4			0.0		28.3			85.1
Internally allocated interest ⁽¹⁾		0.0		0.0		3.3			0.0		(3.3	)		0.0
Provision (benefit) for income taxes		51.3		13.7		(1.0	)		0.0		(12.6	)		51.4
Net income from continuing operations		82.4		21.7		3.7			0.0		(15.0	)		92.8
Income from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0		0.1			0.1
Net income attributable to TECO Energy	$	82.4	$	21.7	$	3.7		$	0.0	$	(14.9	)	$	92.9

2012
Revenues - external	$	952.9	$	203.7	$	288.1		$	0.0	$	4.9		$	1,449.6
Sales to affiliates		0.5		1.3		0.0			0.0		(1.8	)		0.0

Total revenues		953.4		205.0		288.1			0.0		3.1			1,449.6
Depreciation and amortization		117.0		25.0		20.8			0.0		0.7			163.5
Total interest charges ⁽¹⁾		59.5		8.9		3.6			0.0		24.2			96.2
Internally allocated interest ⁽¹⁾		0.0		0.0		3.5			0.0		(3.5	)		0.0
Provision (benefit) for income taxes		50.8		12.6		7.2			0.0		(9.1	)		61.5
Net income from continuing operations		83.4		20.0		22.0			0.0		(15.2	)		110.2
Income from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			14.0		(0.6	)		13.4
Net income attributable to TECO Energy	$	83.4	$	20.0	$	22.0		$	14.0	$	(15.8	)	$	123.6

At June 30, 2013
Total assets	$	6,117.2	$	1,011.9	$	340.3		$	0.0	$	(115.1	)	$	7,354.3

At Dec. 31, 2012
Total assets	$	6,042.3	$	1,009.9	$	356.6		$	164.9	$	(238.8	)	$	7,334.9

(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 2013 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2)

All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. Revenues for TECO Guatemala that were reclassified to discontinued operations were $36.0 million and $68.9 million for the three and six months ended June 30, 2012, respectively. There were no revenues reclassified for the three or six months ended June 30, 2013. See Note 15 for additional information.

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 cash flow 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 has designated all derivatives as cash flow hedges.

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 (see Note 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, 2013, 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, 2013 and Dec. 31, 2012:


Total Derivatives⁽¹⁾
(millions)	June 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2

Total assets	$	0.1	$	0.2


Current liabilities	$	6.8	$	14.6
Long-term liabilities		1.3		0.6

Total liabilities	$	8.1	$	15.2

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

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.


Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
June 30, 2013
Description
Derivative assets	$	0.7		$	(0.6	)	$	0.1
Derivative liabilities	$	(8.7	)	$	0.6		$	(8.1	)

Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

The following table presents the derivative hedges of diesel fuel contracts at June 30, 2013 and Dec. 31, 2012 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, 2013		Dec. 31, 2012
Current assets	$	0.0	$	0.0
Long-term assets		0.0		0.0

Total assets	$	0.0	$	0.0


Current liabilities	$	0.8	$	0.5
Long-term liabilities		0.3		0.4

Total liabilities	$	1.1	$	0.9

The following table presents the derivative hedges of natural gas contracts at June 30, 2013 and Dec. 31, 2012 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, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2

Total assets	$	0.1	$	0.2


Current liabilities	$	6.0	$	14.1
Long-term liabilities		1.0		0.2

Total liabilities	$	7.0	$	14.3

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at June 30, 2013 is a net loss of $8.9 million after tax and accumulated amortization. This compares to a net loss of $9.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2013 and Dec. 31, 2012:

Derivatives Designated as Hedging Instruments

Asset Derivatives

Liability Derivatives

(millions)

Balance Sheet

Fair

Balance Sheet

Fair

June 30, 2013

Location

Value

Location

Value

Commodity Contracts:

Diesel fuel derivatives:

Current

Derivative assets

0.0

Derivative liabilities

0.8

Long-term

Derivative assets

0.0

Derivative liabilities

0.3

Natural gas derivatives:

Current

Derivative assets

0.1

Derivative liabilities

6.0

Long-term

Derivative assets

0.0

Derivative liabilities

1.0

Total derivatives designated as hedging instruments

0.1

8.1

Asset Derivatives

Liability Derivatives

(millions)

Balance Sheet

Fair

Balance Sheet

Fair

Dec. 31, 2012

Location

Value

Location

Value

Commodity Contracts:

Diesel fuel derivatives:

Current

Derivative assets

0.0

Derivative liabilities

0.5

Long-term

Derivative assets

0.0

Derivative liabilities

0.4

Natural gas derivatives:

Current

Derivative assets

0.0

Derivative liabilities

14.1

Long-term

Derivative assets

0.2

Derivative liabilities

0.2

Total derivatives designated as hedging instruments

0.2

15.2

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of June 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives

Asset Derivatives

Liability Derivatives

(millions)

Balance Sheet

Fair

Balance Sheet

Fair

June 30, 2013

Location ⁽¹⁾

Value

Location ⁽¹⁾

Value

Commodity Contracts:

Natural gas derivatives:

Current

Regulatory liabilities

0.1

Regulatory assets

6.0

Long-term

Regulatory liabilities

0.0

Regulatory assets

1.0

Total

0.1

7.0

(millions)

Balance Sheet

Fair

Balance Sheet

Fair

Dec. 31, 2012

Location ⁽¹⁾

Value

Location ⁽¹⁾

Value

Commodity Contracts:

Natural gas derivatives:

Current

Regulatory liabilities

0.0

Regulatory assets

14.1

Long-term

Regulatory liabilities

0.2

Regulatory assets

0.2

Total

0.2

14.3

(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, 2013, net pretax losses of $5.9 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 table presents 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:	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
(millions)	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⁾
2013
Interest rate contracts	$	0.0		Interest expense	$	(0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.4	)	Mining related costs		(0.1	)

Total	$	(0.4	)		$	(0.3	)

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	)

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


For the six months ended June 30:	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
(millions)	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⁾
2013
Interest rate contracts	$	0.0		Interest expense	$	(0.4	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)	Mining related costs		(0.1	)

Total	$	(0.2	)		$	(0.5	)

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	)

(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, 2013 and 2012, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges 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
2013
Interest rate swaps	$	0.0		$	0.0		$	(0.4	)
Diesel fuel derivatives		(1.1	)		(0.2	)		(0.1	)

Total	$	(1.1	)	$	(0.2	)	$	(0.5	)

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	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2015 for financial natural gas and Dec. 31, 2014 for financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of June 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:


(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2013		0.0		3.5		0.0		19.4
2014		0.0		2.0		0.0		12.3
2015		0.0		0.0		0.0		2.2

Total		0.0		5.5		0.0		33.9

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 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, 2013, 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.

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, 2013:


Contingent Features
(millions) At June 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(8.1	)	$	(8.1	)	$	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, 2013 and Dec. 31, 2012. 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.


Recurring Fair Value Measures
	At fair value as of June 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Diesel fuel swaps		0.0		0.0		0.0		0.0

Total	$	0.0	$	0.1	$	0.0	$	0.1


Liabilities
Natural gas swaps	$	0.0	$	7.0	$	0.0	$	7.0
Diesel fuel swaps		0.0		1.1		0.0		1.1

Total	$	0.0	$	8.1	$	0.0	$	8.1


	At fair value as of Dec. 31, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.0		0.0		0.0

Total	$	0.0	$	0.2	$	0.0	$	0.2


Liabilities
Natural gas swaps	$	0.0	$	14.3	$	0.0	$	14.3
Diesel fuel swaps		0.0		0.9		0.0		0.9

Total	$	0.0	$	15.2	$	0.0	$	15.2

Natural gas and diesel fuel swaps are OTC 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 (see Note 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, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

14. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

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 $5.0 million and $9.9 million of capacity pursuant to PPAs for the three and six months ended June 30, 2013, respectively, and $20.8 million and $43.3 million for the three and six months ended June 30, 2012, 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, under this PPA. This PPA expired on Dec. 31, 2012.

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. Discontinued Operations

In 2012, TECO Guatemala, Inc. completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. The following table provides selected components of discontinued operations:


Components of income from discontinued operations attributable to TECO Energy
	Three months ended June 30,					Six months ended June 30,
(millions)	2013			2012		2013		2012
Revenues	$	0.0		$	36.0	$	0.0	$	68.9
(Loss) Income from operations		(0.2	)		11.1		0.2		19.5
(Loss) Income from discontinued operations		(0.2	)		11.1		0.2		19.5
Less: Provision for income taxes		0.0			3.5		0.1		5.9
(Loss) Income from discontinued operations, net		(0.2	)		7.6		0.1		13.6
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.1		0.0		0.2
(Loss) Income from discontinued operations attributable to TECO Energy, net	$	(0.2	)	$	7.5	$	0.1	$	13.4

16. Pending Acquisition of New Mexico Gas Company

Stock Purchase Agreement

On May 25, 2013, the company entered into an SPA by and among the company, NMGI and Continental Energy Systems LLC (CES). NMGI is the parent company of NMGC. Pursuant to the terms and subject to the conditions set forth in the SPA, the company will acquire from CES all of the outstanding capital stock of its subsidiary, NMGI, for an aggregate purchase price of $950 million, which includes the assumption of $200 million of senior secured notes at NMGC. The purchase price is subject to certain closing adjustments in accordance with the terms of the SPA. The permanent financing is expected to be a combination of TECO Energy common equity, cash on hand and long-term debt at NMGI and NMNG.

The closing of the acquisition is subject to various customary closing conditions, including, among others (i) clearance under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) receipt of all required regulatory approvals from the New Mexico

Public Regulation Commission, and (iii) subject to certain materiality exceptions, the accuracy of the representations and warranties made by the parties to the SPA and compliance with their respective obligations under the SPA. The Hart-Scott-Rodino waiting period has now expired without any further request for information. The closing of the acquisition is expected to occur in the first quarter of 2014, subject to satisfaction of closing conditions.

The SPA contains customary representations and warranties of the parties, and covenants to, among other things, cooperate on seeking necessary regulatory approvals and access to information. NMGI also agreed to conduct its business and the business of its subsidiary, NMGC, in the ordinary course until the acquisition is consummated and has agreed to cooperate with the company’s efforts to obtain permanent financing. The acquisition is not subject to any financing condition and the company has entered into a credit agreement to provide bridge financing, as described in the section titled TECO Finance Bridge Facility below. The parties have agreed to indemnify each other for breaches of representations, warranties and covenants. Subject to certain exceptions, CES’s aggregate liability with respect to such indemnification obligations is capped at $30 million (subject to a $9.25 million deductible), which will be placed initially into an escrow account at closing to be available to fund indemnification claims.

The SPA contains certain termination rights for CES and the company, including, among others, the right to terminate if the acquisition is not completed by May 25, 2014 (subject to up to a four month extension under certain circumstances related to obtaining required regulatory approvals).

TECO Finance Bridge Facility

On June 24, 2013, the company and TECO Finance entered into a $1.075 billion Senior Unsecured Bridge Credit Agreement (Bridge Facility) among the company as guarantor, TECO Finance as borrower, Morgan Stanley as administrative agent, sole lead arranger and sole book runner, and the lenders named in the Bridge Facility. The Bridge Facility is sized to cover the $950 million purchase price and provide a $125 million credit facility for the operations of NMGC. Under the terms of the Bridge Facility, as of the closing of the NMGI acquisition, the Bridge Facility permits NMGC to be added to the Bridge Facility as a borrower.

Pursuant to the Bridge Facility, upon satisfaction of certain conditions precedent contained therein, the borrowers may borrow up to $1.075 billion. TECO Finance’s obligations under the Bridge Facility are unconditionally guaranteed by the company. The Bridge Facility matures 364 days after the closing of the acquisition. Repaid amounts under the Bridge Facility may not be reborrowed.

The availability of funds under the Bridge Facility is subject to certain conditions including, among others, and in each case, subject to certain exceptions: (i) the absence of a “material adverse effect” on NMGC, consistent with the definitions in the SPA; (ii) the accuracy of the representations and warranties in the Bridge Facility; (iii) the consummation of the acquisition and the absence of certain changes or waivers to the SPA; (iv) the absence of defaults under the Bridge Facility and under certain other credit facilities of the company and its subsidiaries (Existing Credit Facilities); (v) the delivery of certain financial information pertaining to the company and its subsidiaries; (vi) the solvency of the company and its subsidiaries on a consolidated basis, and compliance, on a pro forma basis after giving effect to the acquisition, with all covenants in the Existing Credit Facilities of the company and its subsidiaries; (vii) the amendment of the TECO Credit Agreement to permit the acquisition (which amendment has been completed, as described in Note 6); (viii) the payment of certain transaction fees; and (ix) the delivery of customary closing documents.

The interest rate applicable to the Bridge Facility is, at the borrower’s option, either a floating base rate or a floating Eurodollar rate, in each case, plus an applicable margin ranging from 0.25% to 2.0% depending on the company’s credit rating, and subject to a 0.25% increase for each 90-day period that elapses after the closing of the acquisition.

The Bridge Facility contains certain covenants that, among other things, restrict certain mergers, consolidations, liquidations and dissolutions of the company and certain subsidiaries, sales by the company and certain subsidiaries of all or a substantial part of its assets; certain liens by of the company or certain subsidiaries on all or substantially all of such party’s assets; in each case subject to exceptions substantially similar to those exceptions in the TECO Credit Facility. Under the Bridge Facility, the company must maintain, on a consolidated basis, a total debt to total capitalization ratio of no greater than 0.65 to 1.00 (except with respect to the four fiscal quarters commencing with the quarter in which the acquisition closes, during which it must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00).

Additionally, the Bridge Facility also contains customary events of default, including, without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness, certain events of bankruptcy and insolvency, certain ERISA events, judgments in excess of specified amounts, certain impairments to the guarantee and changes in control.

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 and its subsidiaries as of June 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended as of June 30, 2013 and 2012. The results of operations for the three month and six month periods ended June 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013. 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, 2012 and to the notes on pages 35 through 46 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS


	Page No.

Consolidated Condensed Balance Sheets, June 30, 2013 and Dec. 31, 2012		30-31

Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended June 30, 2013 and 2012		32-33

Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2013 and 2012		34

Notes to Consolidated Condensed Financial Statements		35-46

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.

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited


*Assets*	June 30,			Dec. 31,
(millions)	2013			2012

Property, plant and equipment
Utility plant in service
Electric	$	6,814.4		$	6,654.5
Gas		1,218.8			1,171.9
Construction work in progress		317.4			335.0

Utility plant in service, at original costs		8,350.6			8,161.4
Accumulated depreciation		(2,479.4	)		(2,373.6	)

		5,871.2			5,787.8
Other property, net		7.4			7.3

Total property, plant and equipment, net		5,878.6			5,795.1


Current assets
Cash and cash equivalents		29.1			45.2
Receivables, less allowance for uncollectibles of $1.5 at June 30, 2013 and Dec. 31, 2012, respectively		256.8			213.8
Inventories, at average cost
Fuel		108.0			89.1
Materials and supplies		72.4			72.4
Regulatory assets		47.4			70.3
Derivative assets		0.1			0.0
Taxes receivable		0.0			22.1
Deferred income taxes		18.6			20.0
Prepayments and other current assets		17.1			11.5

Total current assets		549.5			544.4


Deferred debits
Unamortized debt expense		15.5			16.1
Regulatory assets		374.1			382.6
Derivative assets		0.0			0.2
Other		3.8			6.2

Total deferred debits		393.4			405.1

Total assets	$	6,821.5		$	6,744.6

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

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited


*Liabilities and Capitalization*	June 30,			Dec. 31,
(millions)	2013			2012

Capitalization
Common stock	$	1,990.4		$	1,970.4
Accumulated other comprehensive loss		(8.3	)		(8.7	)
Retained earnings		314.6			304.6

Total capital		2,296.7			2,266.3
Long-term debt, less amount due within one year		1,849.2			1,932.6

Total capitalization		4,145.9			4,198.9


Current liabilities
Long-term debt due within one year		83.3			0.0
Accounts payable		197.1			188.6
Customer deposits		164.1			163.0
Regulatory liabilities		84.9			105.6
Derivative liabilities		6.0			14.1
Interest accrued		18.9			17.3
Taxes accrued		55.1			13.7
Other		11.8			11.8

Total current liabilities		621.2			514.1


Deferred credits
Deferred income taxes		1,022.9			980.9
Investment tax credits		9.5			9.7
Derivative liabilities		1.0			0.2
Regulatory liabilities		627.3			631.4
Other		393.7			409.4

Total deferred credits		2,054.4			2,031.6


Commitments and Contingencies (see Note 9)

Total liabilities and capitalization	$	6,821.5		$	6,744.6

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

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited


	Three months ended June 30,
(millions)	2013			2012
Revenues
Electric (includes franchise fees and gross receipts taxes of $21.5 in 2013 and $23.4 in 2012)	$	502.8		$	506.6
Gas (includes franchise fees and gross receipts taxes of $5.2 in 2013 and $4.9 in 2012)		101.3			93.8

Total revenues		604.1			600.4

Expenses
Regulated operations and maintenance
Fuel		174.5			167.9
Purchased power		20.5			31.2
Cost of natural gas sold		40.9			36.5
Other		129.5			114.2
Depreciation and amortization		74.0			72.0
Taxes, other than income		45.8			46.9

Total expenses		485.2			468.7

Income from operations		118.9			131.7

Other income
Allowance for other funds used during construction		1.4			0.5
Other income, net		1.3			0.4

Total other income		2.7			0.9

Interest charges
Interest on long-term debt		26.4			31.3
Other interest		1.0			3.0
Allowance for borrowed funds used during construction		(0.8	)		(0.3	)

Total interest charges		26.6			34.0

Income before provision for income taxes		95.0			98.6
Provision for income taxes		36.5			37.6

Net income		58.5			61.0

Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges		0.2			(4.7	)

Total other comprehensive income (loss), net of tax		0.2			(4.7	)

Comprehensive income	$	58.7		$	56.3

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

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited


	Six months ended June 30,
(millions)	2013			2012
Revenues
Electric (includes franchise fees and gross receipts taxes of $40.5 in 2013 and $43.3 in 2012)	$	920.7		$	953.2
Gas (includes franchise fees and gross receipts taxes of $11.6 in 2013 and $11.1 in 2012)		223.2			203.7

Total revenues		1,143.9			1,156.9

Expenses
Regulated operations and maintenance
Fuel		314.5			325.4
Purchased power		35.1			59.4
Cost of natural gas sold		90.4			78.1
Other		250.1			226.3
Depreciation and amortization		146.0			142.0
Taxes, other than income		90.3			92.3

Total expenses		926.4			923.5

Income from operations		217.5			233.4

Other income
Allowance for other funds used during construction		2.5			0.9
Other income, net		2.5			0.9

Total other income		5.0			1.8

Interest charges
Interest on long-term debt		52.9			63.0
Other interest		1.9			5.9
Allowance for borrowed funds used during construction		(1.4	)		(0.5	)

Total interest charges		53.4			68.4

Income before provision for income taxes		169.1			166.8
Provision for income taxes		65.0			63.4

Net income		104.1			103.4

Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges		0.4			(4.5	)

Total other comprehensive income (loss), net of tax		0.4			(4.5	)

Comprehensive income	$	104.5		$	98.9

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

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited


	Six months ended June 30,
(millions)	2013			2012
Cash flows from operating activities
Net income	$	104.1		$	103.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		146.0			142.0
Deferred income taxes		42.6			65.3
Investment tax credits		(0.2	)		(0.1	)
Allowance for funds used during construction		(2.5	)		(0.9	)
Gain on sale of business/assets, pretax		0.0			(0.2	)
Deferred recovery clauses		(5.9	)		(12.9	)
Receivables, less allowance for uncollectibles		(43.0	)		(26.5	)
Inventories		(18.9	)		(9.6	)
Prepayments		(5.6	)		(8.2	)
Taxes accrued		63.5			49.1
Interest accrued		1.6			3.5
Accounts payable		13.9			(17.3	)
Other		(0.2	)		5.7

Cash flows from operating activities		295.4			293.3

Cash flows from investing activities
Capital expenditures		(239.9	)		(215.6	)
Allowance for funds used during construction		2.5			0.9
Net proceeds from sale of assets		0.0			0.3

Cash flows used in investing activities		(237.4	)		(214.4	)

Cash flows from financing activities
Capital contributions		20.0			0.0
Proceeds from long-term debt issuance		0.0			290.3
Repayment of long-term debt/Purchase in lieu of redemption		0.0			(204.5	)
Dividends		(94.1	)		(94.2	)

Cash flows used in financing activities		(74.1	)		(8.4	)

Net (decrease) increase in cash and cash equivalents		(16.1	)		70.5
Cash and cash equivalents at beginning of period		45.2			13.9

Cash and cash equivalents at end of period	$	29.1		$	84.4

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

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2012 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. For the periods presented, no VIEs have been consolidated (see Note 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, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended June 30, 2013 and 2012. The results of operations for the three and six months ended June 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

Revenues

Accounting for Franchise Fees and Gross Receipts

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.

Reclassifications

Certain reclassifications were made to prior year amounts to conform to current period presentation. Income tax expense related to regulated operations was previously included within income from operations as it is part of the determination of utility revenue requirements. Income tax expense is now presented directly above net income to conform to the TECO Energy, Inc. presentation. For prior periods, this change results in an increase in income from operations for the amount of income tax expense reclassified. None of the reclassifications affected TEC’s net income in any period.

2. New Accounting Pronouncements

Comprehensive Income

In February 2013, the FASB issued guidance requiring improved disclosures of significant reclassifications out of AOCI and their corresponding effect on net income. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2012. TEC has adopted this guidance as required. It has no effect on TEC’s results of operations, financial position or cash flows.

3. Regulatory

Base Rates-Tampa Electric

Storm Damage Cost Recovery

Regulatory Assets and Liabilities

Details of the regulatory assets and liabilities as of June 30, 2013 and Dec. 31, 2012 are presented in the following table:


Regulatory Assets and Liabilities
(millions)	June 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	67.0	$	67.2

Other:
Cost-recovery clauses		21.0		42.9
Postretirement benefit asset		267.9		276.1
Deferred bond refinancing costs ⁽²⁾		8.6		9.2
Environmental remediation		47.1		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5

Total other regulatory assets		354.5		385.7

Total regulatory assets		421.5		452.9
Less: Current portion		47.4		70.3

Long-term regulatory assets	$	374.1	$	382.6

Regulatory liabilities:
Regulatory tax liability ⁽¹⁾	$	13.9	$	14.6

Other:
Cost-recovery clauses		53.2		73.9
Transmission and delivery storm reserve		53.4		50.4
Deferred gain on property sales ⁽³⁾		2.7		3.4
Provision for stipulation and other		1.1		1.0
Accumulated reserve - cost of removal		587.9		593.7

Total other regulatory liabilities		698.3		722.4

Total regulatory liabilities		712.2		737.0
Less: Current portion		84.9		105.6

Long-term regulatory liabilities	$	627.3	$	631.4

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

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

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

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


Regulatory Assets
(millions)	June 30, 2013		Dec. 31, 2012
Clause recoverable ⁽¹⁾	$	25.2	$	47.0
Components of rate base ⁽²⁾		270.7		279.1
Regulatory tax assets ⁽³⁾		67.0		67.2
Capital structure and other ⁽³⁾		58.6		59.6

Total	$	421.5	$	452.9

(1)	To be recovered through recovery mechanisms 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)

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 six months ended June 30, 2013 and 2012 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 2011 consolidated federal income tax return during 2012. The U.S. federal statute of limitations remains open for the year 2009 and forward. Years 2012 and 2013 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 2013. 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 2009 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 in Note 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, 2013 and 2012, respectively, was $5.6 million and $5.0 million for pension benefits, and $2.4 million and $3.1 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2013 and 2012, respectively, was $10.9 million and $9.2 million for pension benefits, and $5.0 million and $6.2 million for other postretirement benefits.

Included in the benefit expenses discussed above, for the three and six months ended June 30, 2013, TEC reclassed $4.2 million and $8.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

At June 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:


Credit Facilities
	June 30, 2013						Dec. 31, 2012
(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	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0

Total	$	475.0	$	0.0	$	1.5	$	475.0	$	0.0	$	1.5

(1)	Borrowings outstanding are reported as notes payable.

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

At June 30, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at June 30, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2013, TEC’s total long-term debt had a carrying amount of $1,932.5 million and an estimated fair market value of $2,179.7 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $1,932.6 million and an estimated fair market value of $2,270.3 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. Other Comprehensive Income


Other Comprehensive Income	Three months ended June 30,									Six months ended June 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2013
Unrealized loss on cash flow hedges	$	0.0		$	0.0		$	0.0		$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		0.4			(0.2	)		0.2			0.7			(0.3	)		0.4

Gain on cash flow hedges		0.4			(0.2	)		0.2			0.7			(0.3	)		0.4

Total other comprehensive income	$	0.4		($	0.2	)	$	0.2		$	0.7		($	0.3	)	$	0.4

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	)


Accumulated Other Comprehensive Loss
(millions)	June 30, 2013			Dec. 31, 2012
Net unrealized losses from cash flow hedges ⁽¹⁾	$	(8.3	)	$	(8.7	)

Total accumulated other comprehensive loss	$	(8.3	)	$	(8.7	)

(1)	Net of tax benefit of $5.2 million and $5.5 million as of June 30, 2013 and Dec. 31, 2012, respectively.

9. 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.

Legal Proceedings

TEC believes the claims in each of the pending actions described above in this item are without merit and intends to defend each matter vigorously. TEC is unable at this time to estimate the possible loss or range of loss with respect to these matters.

Superfund and Former Manufactured Gas Plant Sites

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.

Environmental Protection Agency 114 Letter

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2013 is as follows:


Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After⁽¹⁾ 2017		Total		Liabilities Recognized at June 30, 2013
Tampa Electric ⁽²⁾	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

(1)	These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2017.

(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, 2013. 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, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2013, TEC was in compliance with all applicable financial covenants.

10. Segment Information


(millions) Three months ended June 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2013
Revenues - external	$	502.8	$	101.3	$	0.0		$	604.1
Sales to affiliates		0.1		0.5		(0.6	)		0.0

Total revenues		502.9		101.8		(0.6	)		604.1
Depreciation and amortization		60.8		13.2		0.0			74.0
Total interest charges		23.3		3.3		0.0			26.6
Provision for income taxes		31.5		5.0		0.0			36.5
Net income	$	50.6	$	7.9	$	0.0		$	58.5

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


Six months ended June 30,
2013
Revenues - external	$	920.7	$	223.2	$	0.0		$	1,143.9
Sales to affiliates		0.2		0.5		(0.7	)		0.0

Total revenues		920.9		223.7		(0.7	)		1,143.9
Depreciation and amortization		119.8		26.2		0.0			146.0
Total interest charges		46.7		6.7		0.0			53.4
Provision for income taxes		51.3		13.7		0.0			65.0
Net income	$	82.4	$	21.7	$	0.0		$	104.1

Total assets at June 30, 2013	$	5,849.9	$	976.0	($	4.4	)	$	6,821.5

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 Dec. 31, 2012	$	5,760.4	$	970.9	$	13.3		$	6,744.6

11. 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 cash flow 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.

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 has designated all derivatives as cash flow hedges.

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 (see Note 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, 2013, 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, 2013 and Dec. 31, 2012 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, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2

Total assets	$	0.1	$	0.2


Current liabilities ⁽¹⁾	$	6.0	$	14.1
Long-term liabilities		1.0		0.2

Total liabilities	$	7.0	$	14.3

(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, 2013 is a net loss of $8.3 million after tax and accumulated amortization. This compares to a net loss of $8.7 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.


Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
June 30, 2013
Description
Derivative assets	$	0.7		$	(0.6	)	$	0.1
Derivative liabilities	$	(7.6	)	$	0.6		$	(7.0	)

Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of June 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives

Asset Derivatives

Liability Derivatives

(millions)

June 30, 2013

Balance Sheet
Location ⁽¹⁾

Fair
Value

Balance Sheet
Location ⁽¹⁾

Fair
Value

Commodity Contracts:

Natural gas derivatives:

Current

Regulatory liabilities

0.1

Regulatory assets

6.0

Long-term

Regulatory liabilities

0.0

Regulatory assets

1.0

Total

0.1

7.0


(millions) Dec. 31, 2012	Balance Sheet Location ⁽¹⁾	Fair Value		Balance Sheet Location ⁽¹⁾	Fair Value
Commodity Contracts:

Natural gas derivatives:
Current	Regulatory liabilities	$	0.0	Regulatory assets	$	14.1
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.2

Total		$	0.2		$	14.3

(1)

Based on the fair value of the instruments at June 30, 2013, net pretax losses of $5.9 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 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:
2013
Interest rate contracts:	Interest expense	$	(0.2	)	$	(0.4	)

Total		$	(0.2	)	$	(0.4	)

2012
Interest rate contracts:	Interest expense	$	(0.2	)	$	(0.4	)

Total		$	(0.2	)	$	(0.4	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and six months ended June 30, 2013 and 2012, 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, 2015 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of June 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:


(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2013		0.0		19.4
2014		0.0		12.3
2015		0.0		2.2

Total		0.0		33.9

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, 2013, 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.

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, 2013:


Contingent Features
(millions) June 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(7.0	)	$	(7.0	)	$	0.0

12. 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, 2013 and Dec. 31, 2012. 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.


Recurring Derivative Fair Value Measures
	At fair value as of June 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1

Total	$	0.0	$	0.1	$	0.0	$	0.1


Liabilities
Natural gas swaps	$	0.0	$	7.0	$	0.0	$	7.0

Total	$	0.0	$	7.0	$	0.0	$	7.0


	At fair value as of Dec. 31, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2

Total	$	0.0	$	0.2	$	0.0	$	0.2


Liabilities
Natural gas swaps	$	0.0	$	14.3	$	0.0	$	14.3

Total	$	0.0	$	14.3	$	0.0	$	14.3

Natural gas swaps are OTC 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 (see Note 11).

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, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

13. Variable Interest Entities

TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

Item 2.

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

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this press release, except as may be required by law. Factors that could impact actual results include: the risk that the transaction to acquire New Mexico Gas Company may not be consummated or that the anticipated benefits from the transaction cannot be fully realized; regulatory actions by federal, state or local authorities, including the potential outcome of Tampa Electric’s requested base rate increase before the FPSC, and the required approval by the New Mexico Public Regulation Commission for the acquisition of New Mexico Gas Co.; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida and New Mexico economies and demand for TECO Coal’s production; costs for alternate fuels used for power generation affecting demand for TECO Coal’s thermal coal production; operating costs and environmental or safety regulations affecting production levels and margins at TECO Coal; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; and the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost at all of the operating companies; natural gas demand at the utilities; 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 Part II of this Report on Form 10-Q, in TECO Energy, Inc.‘s Annual Report on Form 10-K for the period ended Dec. 31, 2012, and as updated in subsequent filings with the Securities and Exchange Commission.


Earnings Summary - Unaudited
	Three months ended June 30,					Six months ended June 30,
(millions, except per share amounts)	2013			2012		2013		2012
Consolidated revenues	$	735.9		$	752.5	$	1,397.0	$	1,449.6

Discontinued operations attributable to TECO Energy		(0.2	)		7.5		0.1		13.4

Net income attributable to TECO Energy	$	51.4		$	73.1	$	92.9	$	123.6

Average common shares outstanding
Basic		215.0			214.3		214.8		214.1

Diluted		215.5			215.2		215.3		215.3

Earnings per share - basic
Continuing operations	$	0.24		$	0.30	$	0.43	$	0.51
Discontinued operations		0.00			0.04		0.00		0.07

Earnings per share attributable to TECO Energy - Basic	$	0.24		$	0.34	$	0.43	$	0.58

Earnings per share - diluted
Continuing operations	$	0.24		$	0.30	$	0.43	$	0.50
Discontinued operations		0.00			0.04		0.00		0.07

Earnings per share attributable to TECO Energy - Diluted	$	0.24		$	0.34	$	0.43	$	0.57

Operating Results

Three Months Ended June 30, 2013

TECO Energy, Inc. reported second-quarter 2013 net income of $51.4 million, or $0.24 per share, compared with $73.1 million, or $0.34 per share, in the second quarter of 2012. Net income from continuing operations was $51.6 million, or $0.24 per share, in the 2013 second quarter, compared with $65.6 million, or $0.30 per share, for the same period in 2012. Net income from continuing operations in 2013 was reduced by $1.8 million of costs associated with the pending acquisition of NMGC. The 2013 second-quarter cost of $0.2 million reported in discontinued operations was related to the 2012 sale of TECO Guatemala.

Six Months Ended June 30, 2013

Year-to-date net income was $92.9 million, or $0.43 per share, compared with $123.6 million, or $0.58 per share, in the same period in 2012. Net income from continuing operations was $92.8 million, or $0.43 per share, in the 2013 year-to-date period, compared with $110.2 million, or $0.51 per share, for the same period in 2012. Net income from continuing operations in 2013 was reduced by $1.8 million of costs associated with the pending acquisition of NMGC.

Operating Company Results

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

Tampa Electric - Electric Division

Tampa Electric’s net income for the second quarter of 2013 was $50.6 million, compared with $52.0 million for the same period in 2012. Results for the quarter reflected a 1.4% higher average number of customers, lower energy sales due to milder weather, lower interest expense, and higher depreciation and operations and maintenance expenses. Second-quarter net income in 2013 included $1.4 million of Allowance for Funds Used During Construction (AFUDC) equity, which represents allowed equity cost capitalized to construction costs, compared with $0.5 million in the 2012 quarter.

Total degree days in Tampa Electric’s service area in the second quarter of 2013 were 2% above normal, and 3% below the same period in 2012, resulting in pretax base revenue only slightly lower than in 2012. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 0.8% in the second quarter of 2013 compared with the same period in 2012. 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. Sales to weather-sensitive residential and commercial customers decreased in the second quarter of 2013 as a result of generally milder weather than in 2012.

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost-recovery clauses, increased $2.9 million in the 2013 quarter, reflecting primarily higher costs for scheduled generating-unit outage expenditures and higher costs to operate and maintain the transmission and distribution systems. Depreciation and amortization expense increased $0.7 million in 2013 due to additions to facilities to serve customers. Interest expense decreased $3.8 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

Year-to-date net income was $82.4 million, compared with $83.4 million in the 2012 period, driven primarily by lower energy sales due to generally milder weather and higher depreciation and operations and maintenance expenses, partially offset by 1.4% higher average number of customers.

Year-to-date total degree days in Tampa Electric’s service area were 1% below normal, and 7% below the prior year-to-date period, reflecting generally milder weather. Pretax base revenue was more than $5.0 million lower than in 2012, primarily reflecting lower sales to weather-sensitive residential and commercial customers from the milder weather and voluntary conservation that typically occurs during periods without extreme weather.

In the 2013 year-to-date period, total net energy for load was 2.2% lower than the same period in 2012. Milder weather reduced sales to higher-margin residential customers, while phosphate and industrial-other sales were higher. Sales to interruptible industrial-phosphate customers increased due to the factors described above. Higher sales to industrial-other customers reflect the improvements in the Florida economy.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, increased $5.0 million in the 2013 year-to-date period, reflecting the same factors as in the second quarter and higher employee-related expenses. Compared to the 2012 year-to-date period, depreciation and amortization expense increased $1.7 million, reflecting additions to facilities to serve customers, partially offset by a $1.0 million favorable adjustment to depreciation expense related to combustion turbine repairs. Interest expense decreased $7.9 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

A summary of Tampa Electric’s regulated operating statistics for the six months ended June 30, 2013 and 2012 follows:


	Operating Revenues								Kilowatt-hour sales
(millions, except average customers)	2013		2012			% Change			2013		2012		% Change
*Three months ended June 30,*
By Customer Type
Residential	$	226.2	$	248.7			(9.0	)		2,061.9		2,179.5		(5.4	)
Commercial		143.5		156.8			(8.5	)		1,501.0		1,588.0		(5.5	)
Industrial - Phosphate		18.9		18.8			0.5			235.1		225.8		4.1
Industrial - Other		25.5		26.3			(3.0	)		287.5		284.8		0.9
Other sales of electricity		44.4		46.0			(3.5	)		460.3		458.3		0.4
Deferred and other revenues ⁽¹⁾		26.0		(7.0	)		471.4

		484.5		489.6			(1.0	)		4,545.8		4,736.4		(4.0	)
Sales for resale		3.5		3.5			0.0			88.5		52.8		67.6
Other operating revenue		14.9		13.7			8.8

	$	502.9	$	506.8			(0.8	)		4,634.3		4,789.2		(3.2	)

Average customers (thousands)		693.8		684.1			1.4
Retail net energy for load (kilowatt hours)										5,029.0		5,068.3		(0.8	)


*Six months ended June 30,*
By Customer Type
Residential	$	415.8	$	445.9			(6.8	)		3,787.1		3,904.6		(3.0	)
Commercial		274.2		296.7			(7.6	)		2,854.3		2,981.9		(4.3	)
Industrial - Phosphate		36.7		37.2			(1.3	)		457.1		448.5		1.9
Industrial - Other		48.8		50.4			(3.2	)		550.4		543.1		1.3
Other sales of electricity		85.7		88.7			(3.4	)		880.8		874.4		0.7
Deferred and other revenues ⁽¹⁾		23.2		0.5			4,540.0

		884.4		919.4			(3.8	)		8,529.7		8,752.5		(2.5	)
Sales for resale		4.9		6.7			(26.9	)		129.3		117.5		10.0
Other operating revenue		31.6		27.3			15.8

	$	920.9	$	953.4			(3.4	)		8,659.0		8,870.0		(2.4	)

Average customers (thousands)		692.0		682.4			1.4
Retail net energy for load (kilowatt hours)										9,116.9		9,325.1		(2.2	)

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

Tampa Electric Company - Natural Gas Division (PGS)

Peoples Gas System reported net income of $7.9 million for the second quarter, compared with $9.0 million in 2012. Second-quarter results in 2013 reflected average customer growth of 1.4% and higher therm sales to all retail customer classes, aided in part by cooler-than-normal early spring weather. Therms sold to commercial and industrial customers increased due to improving economic conditions. Sales to power generation customers and off-system sales decreased due to the expiration of two contracts with power generators, new participants in the market, and higher natural gas prices in 2013 compared to 2012. In the 2013 period, higher non-fuel operations and maintenance expense was partially offset by lower interest expense.

Peoples Gas reported net income of $21.7 million for the year-to-date period, compared with $20.0 million in the same period in 2012. Results reflect a 1.3% higher average number of customers, and higher therm sales to all retail customer classes due to more-normal weather and improving economic conditions. Sales to power generation customers and off-system sales decreased due to the same reasons as in the second quarter. Non-fuel operations and maintenance expense increased $1.3 million compared to the 2012 period. Interest expense decreased $1.3 million, due to lower long-term debt interest rates and a lower interest rate on customer deposits.

A summary of PGS’s regulated operating statistics for the six months ended June 30, 2013 and 2012 follows:


	Operating Revenues							Therms
(millions, except average customers)	2013		2012		% Change			2013		2012		% Change
*Three months ended June 30,*
By Customer Type
Residential	$	29.6	$	28.3		4.6			16.3		14.0		16.4
Commercial		33.0		32.1		2.8			107.3		100.4		6.9
Industrial		3.0		2.2		36.4			68.5		57.7		18.7
Off system sales		20.4		18.9		7.9			46.6		66.3		(29.7	)
Power generation		2.5		3.3		(24.2	)		180.4		274.8		(34.4	)
Other revenues		10.7		8.0		33.8

	$	99.2	$	92.8		6.9			419.1		513.2		(18.3	)

By Sales Type
System supply	$	60.4	$	58.4		3.4			70.5		89.1		(20.9	)
Transportation		28.2		26.4		6.8			348.6		424.1		(17.8	)
Other revenues		10.7		8.0		33.8

	$	99.3	$	92.8		7.0			419.1		513.2		(18.3	)

Average customers (thousands)		347.8		343.1		1.4


*Six months ended June 30,*
By Customer Type
Residential	$	71.9	$	68.9		4.4			45.8		41.0		11.7
Commercial		72.2		70.7		2.1			232.1		218.9		6.0
Industrial		6.6		4.6		43.5			139.7		113.3		23.3
Off system sales		38.7		32.1		20.6			97.1		110.3		(12.0	)
Power generation		5.6		6.7		(16.4	)		385.4		483.4		(20.3	)
Other revenues		23.2		18.1		28.2

	$	218.2	$	201.1		8.5			900.1		966.9		(6.9	)

By Sales Type
System supply	$	134.4	$	126.9		5.9			160.4		171.9		(6.7	)
Transportation		60.6		56.1		8.0			739.7		795.0		(7.0	)
Other revenues		23.2		18.1		28.2

	$	218.2	$	201.1		8.5			900.1		966.9		(6.9	)

Average customers (thousands)		347.1		342.6		1.3

TECO Coal

TECO Coal reported second-quarter net income of $0.7 million on sales of 1.5 million tons, compared with $12.2 million on sales of 1.6 million tons in the same period in 2012. In 2013, second-quarter results reflect an average net per-ton selling price, excluding transportation allowances, of almost $86 per ton, compared to more than $94 per ton in 2012. In the second quarter of 2013, the all-in total per-ton cost of sales was almost $86 per ton, which is higher than full-year guidance, but lower than in the first quarter of 2013. The cost of sales in June was in line with full year 2013 cost guidance. Due to the effects of tax percentage depletion, TECO Coal recorded a $1.0 million income tax benefit in the second quarter of 2013, compared with a 24% effective income tax rate in the 2012 period.

TECO Coal recorded year-to-date 2013 net income of $3.7 million on sales of 2.8 million tons, compared with $22.0 million on sales of 3.0 million tons in the 2012 period. The 2013 year-to-date average net per-ton selling price was more than $87 per ton, compared with $95 per ton in 2012. The all-in total per-ton cost of sales was more than $86 per ton, which was essentially unchanged from 2012. The cost of sales in the first quarter of 2013 included some higher-cost tons from December inventory that included costs associated with personnel reductions and with idling certain mining operations. Due to the effects of tax percentage depletion, TECO Coal recorded a $1.0 million income tax benefit in 2013, compared with a 25% effective income tax rate in the 2012 period.

Parent & other

The cost for Parent & other in the second quarter of 2013 was $7.8 million, compared with a cost of $7.5 million in the same period in 2012. The second quarter 2013 cost of $7.8 million includes $1.8 million of costs associated with the pending acquisition of NMGC. Largely offsetting these costs in the 2013 quarter were favorable tax adjustments recorded at Parent.

The 2013 year-to-date cost for Parent & other was $14.9 million, compared with $15.8 million for the 2012 period. Year-to-date cost in 2013 includes $1.8 million of costs associated with the pending acquisition of NMGC.

Results from Discontinued operations of ($0.2) and $0.1 for the quarter and year-to-date periods, respectively, represent costs and benefits recorded at Parent & other related to the 2012 sale of TECO Guatemala.

2013 Guidance

TECO Energy is maintaining its earnings-per-share guidance for 2013 in a range between $0.90 and $1.00, excluding charges or gains. TECO Energy expects earnings in 2013 to be driven by the factors discussed below.

Tampa Electric expects customer growth consistent with year-to-date trends to continue, and expects total retail energy sales growth to be lower than customer growth due to lower average customer usage. Sales to the lower-margin industrial-phosphate customers had been expected to be lower in 2013 due to increased self-generation by these customers; however there have been delays to increasing self-generation, which is expected to result in higher sales than previously forecast. Operations and maintenance expenses are expected to increase in 2013 due to increased expenses to operate the system and reliably serve customers, and higher employee-related expenses including higher pension expense driven by lower discount rate assumptions in the current interest rate environment. For 2013, Tampa Electric expects its full-year 13-month average return on equity (ROE) to be less than 9%.

Peoples Gas expects to continue to earn above the middle of its allowed ROE range of 9.75% to 11.75% from moderate customer growth, which is expected to continue in 2013 in line with the trends experienced in 2012. It also expects to benefit from continued interest from customers utilizing petroleum and other fuel sources to convert to natural gas due to the attractive economics.

TECO Coal has 95% of its expected sales of between 5.2 million and 5.7 million tons contracted for 2013. The unsold tons are primarily High-Vol-A coal, which are forecast to be sold later in 2013. The product mix is expected to be about 50% specialty coals, which include stoker, metallurgical and PCI coals, and the remainder utility steam coal. The average selling price across all products is expected to be more than $86 per ton. The all-in total cost of production is expected to be above the middle of the previously announced range of $81 to $85 per ton. In June, TECO Coal took further actions to eliminate production and reduce costs from certain high-cost mines. Because of the tax benefit in the second quarter, TECO Coal’s full-year 2013 effective income tax rate is expected to be significantly less than the previously forecast 25%.

New Mexico Gas Intermediate, Inc. Acquisition

In May, the company announced that it had entered into an agreement to purchase the outstanding stock of NMGI, the parent company of NMGC, for a purchase price of $950 million, including the assumption of $200 million of existing NMGC debt (see Note 16 to the TECO Energy, Inc. Consolidated Condensed Financial Statements).

The company subsequently filed for anti-trust approval through a Hart-Scott-Rodino filing. The waiting period for comments has expired. On July 9, the company filed with the New Mexico Public Regulation Commission for approval of the transaction. Integration planning among the two companies has commenced and progress is being made.

Income Taxes

The provision for income taxes from continuing operations for the six month periods ended June 30, 2013 and 2012 were $51.4 million and $61.5 million, respectively. The provision for income taxes in the six months ended June 30, 2013 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, 2013 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 TEC credit facilities.


At June 30, 2013			Tampa Electric Company		Other Companies		TECO Finance/Parent
(millions)	Consolidated		Tampa Electric Company		Other Companies		TECO Finance/Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts/Letters of Credit		1.5		1.5		0.0		0.0

Available credit facilities		673.5		473.5		0.0		200.0
Cash and short-term investments		153.3		29.1		3.8		120.4

Total liquidity	$	826.8	$	502.6	$	3.8	$	320.4

On May 25, 2013, TECO Energy entered into a SPA to purchase all of the outstanding capital stock of NMGI, for an aggregate purchase price of $950 million, which includes the assumption of $200 million of senior secured notes at NMGC, NMGI’s wholly-owned subsidiary. On June 24, 2013, TECO Energy and TECO Finance entered into a $1.075 billion syndicated bridge facility, with Morgan Stanley as administrative agent, in order to fund the acquisition. Permanent financing is expected to be a combination of common equity, cash on hand and long-term debt at NMGI and NMGC. See Note 16 to the TECO Energy, Inc. Consolidated Condensed Financial Statements.

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 Liquidity and Capital Resources section above). 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, 2013, 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, 2013. Reference is made to the specific agreements and instruments for more details.


Significant Financial Covenants
(millions, unless otherwise indicated)
Instrument	Financial Covenant⁽¹⁾	Requirement/Restriction			Calculation at June 30, 2013
TEC
Credit facility⁽²⁾	Debt/capital		Cannot exceed 65%			45.6%
Accounts receivable credit facility⁽²⁾	Debt/capital		Cannot exceed 65%			45.6%
6.25% senior notes	Debt/capital		Cannot exceed 60%			45.6%
	Limit on liens⁽³⁾		Cannot exceed $700			$0 liens outstanding

TECO Energy/TECO
Finance
Credit facility⁽²⁾	Debt/capital		Cannot exceed 65%			56.1%
TECO Finance 6.75% notes	Restrictions on secured debt⁽⁴⁾		⁽⁵	⁾		⁽⁵	⁾

(1)	As defined in each applicable instrument.

(2)	See Note 6 to the TECO Energy, Inc. Consolidated Condensed Financial Statements for a description of the credit facilities, including the June 24, 2013 amendment.

(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 indenture 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, 2013
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	A3	A–
TECO Energy/TECO Finance	BBB	Baa2	BBB

Upon announcing the acquisition of NMGC, Standard & Poor’s and Moody’s Investors Service affirmed the current credit ratings of TECO Energy, TECO Finance and Tampa Electric. Fitch Ratings placed the credit ratings of TECO Energy, TECO Finance and Tampa Electric on ratings watch negative.

S&P, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign TECO Energy, TECO Finance and TEC’s senior unsecured debt 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. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TECO 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 our ability to borrow and may increase financing costs, which may decrease earnings. These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our 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 in Notes 7 and 13 to the TECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 30, 2013, the fair value of derivatives was not materially affected by nonperformance risk.

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, see TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 2% from Dec. 31, 2012 to June 30, 2013. For natural gas, the company maintained a similar volume hedged as of June 30, 2013 from Dec. 31, 2012.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the six month period ended June 30, 2013:


Changes in Fair Value of Derivatives *(millions)*
Net fair value of derivatives as of Dec. 31, 2012	$	(15.0	)
Additions and net changes in unrealized fair value of derivatives		(5.5	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		12.5

Net fair value of derivatives as of June 30, 2013	$	(8.0	)


*Roll-Forward of Derivative Net Assets (Liabilities) (millions***)
Total derivative net liabilities as of Dec. 31, 2012	$	(15.0	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(5.5	)
Recorded in earnings		0.0
Realized net settlement of derivatives		12.5
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0

Net fair value of derivatives as of June 30, 2013	$	(8.0	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at June 30, 2013:


*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⁾		(6.7	)		(1.3	)		(8.0	)
Model prices ⁽²⁾		0.0			0.0			0.0

Total	$	(6.7	)	$	(1.3	)	$	(8.0	)

(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.

Item 4.

CONTROLS AND PROCEDURES

TECO Energy, Inc.

(a)

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

(b)

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

Tampa Electric Company

(a)

Evaluation of Disclosure Controls and Procedures. 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.

PART II. OTHER INFORMATION

Item 1A.

RISK FACTORS

Federal or state regulation of GHG emissions, depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales. In a June 25, 2013 memorandum to the EPA, President Obama directed that agency to issue new emissions standards for future power plants as well as modified, reconstructed or existing power plants to reduce GHG emissions.

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions. While GHG emission regulations have been proposed, both at the federal and state level, none has been passed at this time and, therefore, costs to reduce GHGs are unknown. Presently there is no viable technology to remove CO₂ post-combustion from conventional coal-fired units such as Tampa Electric’s Big Bend units.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but we cannot be assured that the FPSC would grant such recovery.

The new standards for future power plants and for existing power plants are due in September 2013 and June 2014, respectively. It is unclear how the EPA may design such rules. It is likely that both rules will be subject to legal challenges and litigation, which could have a material impact on both the timing and substance of any proposed new rules.

In the case of TECO Coal, the use of coal to generate electricity is considered a significant source of GHG emissions. New regulations, depending on final form, could cause the consumption of coal to decrease or the cost of sales to increase, which could negatively impact TECO Coal’s earnings.

The acquisition of NMGI may not be completed or regulatory approval may be subject to unfavorable conditions, and if completed, changing market conditions, associated costs and other factors prior to, or following completion, could adversely affect the anticipated benefits of the transaction and the company’s results.

On May 25, 2013, the company entered into a stock purchase agreement to acquire the common stock of New Mexico Gas Intermediate, Inc., the parent company of NMGC. In order to complete this transaction, the company must obtain approval from the New Mexico Public Regulation Commission (PRC). The PRC may not approve the transaction, or may impose terms or conditions on the approval which could delay the completion of the transaction, impose additional costs, or otherwise impact the anticipated benefits of the transaction. In addition, the anticipated benefits of the transaction are based on current estimates of transaction and integration-related costs, which are dependent on financial market conditions and other factors, which may materially change. Negative changes in these factors could have an adverse effect on the anticipated benefits of the transaction or the company’s business, financial condition, results of operations or stock price.

In order to finance the New Mexico Gas Acquisition, we plan to incur additional indebtedness and issue equity securities, which could have an adverse effect on our financial health.

We currently expect to finance the New Mexico Gas Acquisition with a combination of TECO Energy common equity, cash on hand and long-term debt at NMGC and NMGI. Incurrence of additional debt may have an adverse effect on our financial condition and may limit our ability to obtain financing in the future. Furthermore, the issuance of equity securities will result in additional shares outstanding and may have an adverse effect on the market price of our common stock.

Additionally, if we fail to realize the expected benefits from the New Mexico Gas Acquisition or if the financial performance of NMGC does not meet our current expectations, it may have a negative effect on our credit metrics. If we cannot obtain the permanent financing we expect, alternative financing under the Bridge Facility would be on less favorable financial terms. In that event, any debt incurred to replace or refinance the amounts under the Bridge Facility could also be under less favorable terms.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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


	(a) Total Number of Shares (or Units) Purchased⁽¹⁾		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Apr. 1, 2013 – Apr. 30, 2013		416	$	18.17		0.0	$	0.0
May 1, 2013 – May 31, 2013		54,571	$	18.84		0.0	$	0.0
June 1, 2013 – June 30, 2013		690	$	17.15		0.0	$	0.0

Total 2nd Quarter 2013		55,677	$	18.81		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 in Exhibit 95 to this quarterly report.

Item 6.

EXHIBITS

Exhibits - See index on page 58.

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 2, 2013	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 2, 2013	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)

INDEX TO EXHIBITS


Exhibit No.	Description

2.1	Stock Purchase Agreement, dated as of May 25, 2013, by and among TECO Energy, Inc., New Mexico Gas Intermediate, Inc. and Continental Energy Systems LLC (Exhibit 2.1, Form 8-K dated May 28, 2013 of TECO Energy, Inc).	*

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 4, 2012 of TECO Energy, Inc.).

3.2	Bylaws of TECO Energy, Inc., as amended effective May 3, 2012 (Exhibit 3.1, Form 8-K dated May 4, 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 2011 of TECO Energy, Inc. and Tampa Electric Company).

10.1	Commitment Letter, dated as of May 25, 2013, by and among TECO Energy, Inc., TECO Finance, Inc. and Morgan Stanley Senior Funding, Inc. (Exhibit 10.1, Form 8-K dated May 28, 2013 of TECO Energy, Inc).	*

10.2	Senior Unsecured Bridge Credit Agreement, dated as of June 24, 2013, by and among TECO Energy, Inc., as Guarantor, TECO Finance, Inc., as Borrower, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated June 28, 2013 of TECO Energy, Inc).	*

10.3	Amendment No. 1 dated as of June 24, 2013 to the Third Amended and Restated Credit Agreement dated as of October 25, 2011, among TECO Finance, Inc., as Borrower, TECO Energy, Inc. as Guarantor, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Exhibit 10.2, Form 8-K dated June 28, 2013 of TECO Energy, Inc).	*

12.1	Ratio of Earnings to Fixed Charges - TECO Energy, Inc.

12.2	Ratio of Earnings to Fixed Charges - Tampa Electric Company.

31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ⁽¹⁾

32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ⁽¹⁾

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 TEC 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.