TECO Energy 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 13, 2014	Jun. 28, 2013
Document Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Entity Registrant Name	'TECO ENERGY INC	'	'
Entity Central Index Key	'0000350563	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	218,067,617	'
Entity Public Float	'	'	$3.69
Tampa Electric Company [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'TAMPA ELECTRIC CO	'	'
Entity Central Index Key	'0000096271	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	10	'
Entity Public Float	'	'	$0

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$185.20	$200.50
Receivables, less allowance for uncollectibles	287.2	282.7
Inventories, at average cost	'	'
Derivative assets	9.7	0
Regulatory assets	34.3	70.3
Deferred income taxes	100.3	63.3
Prepayments and other current assets	34.9	33.9
Income tax receivables	1.5	0.4
Total current assets	857.7	856.8
Property, plant and equipment	'	'
Construction work in progress	386.7	336.1
Other property	448.3	443.8
Property, plant and equipment, at original costs	9,077.30	8,664
Accumulated depreciation	-2,907.20	-2,695.50
Total property, plant and equipment, net	6,170.10	5,968.50
Other assets	'	'
Regulatory assets	293.1	382.6
Derivative assets	0.3	0.2
Deferred charges and other assets	126.8	126.8
Total other assets	420.2	509.6
Total assets	7,448	7,334.90
Current liabilities	'	'
Long-term debt due within one year	83.3	0
Notes payable	84	0
Accounts payable	261.7	232.8
Customer deposits	164.5	162.9
Regulatory liabilities	85.8	105.6
Derivative liabilities	0.1	14.6
Interest accrued	31.9	33.2
Taxes accrued	34.6	32.1
Other	19.5	19.9
Total current liabilities	765.4	601.1
Other liabilities	'	'
Deferred income taxes	444	277.9
Investment tax credits	9.4	9.7
Regulatory liabilities	631.4	631.4
Derivative liabilities	0.2	0.6
Deferred credits and other liabilities	426.1	549.7
Long-term debt, less amount due within one year	2,837.80	2,972.70
Total other liabilities	4,348.90	4,442
Commitments and Contingencies	'	'
Capital	'	'
Common equity	217.3	216.6
Additional paid in capital	1,581.30	1,564.50
Retained earnings	548.3	541.7
Accumulated other comprehensive loss	-13.2	-31
Total capital	2,333.70	2,291.80
Total liabilities and capital	7,448	7,334.90
Fuel [Member]	'	'
Inventories, at average cost	'	'
Utility inventories	118.7	123.6
Materials and Supplies [Member]	'	'
Inventories, at average cost	'	'
Utility inventories	85.9	82.1
Electric [Member]	'	'
Property, plant and equipment	'	'
Electric	6,934	6,655.80
Gas [Member]	'	'
Property, plant and equipment	'	'
Electric	1,308.30	1,228.30
Tampa Electric Company [Member]	'	'
Current assets	'	'
Cash and cash equivalents	9.8	45.2
Receivables, less allowance for uncollectibles	227.6	213.8
Inventories, at average cost	'	'
Derivative assets	9.5	0
Regulatory assets	34.3	70.3
Deferred income taxes	29.4	20
Prepayments and other current assets	12.5	11.5
Income tax receivables	54.9	22.1
Total current assets	548.5	544.4
Property, plant and equipment	'	'
Construction work in progress	385.3	335
Property, plant and equipment, at original costs	8,568.80	8,161.40
Accumulated depreciation	-2,562.60	-2,373.60
Public utilities, property, plant and equipment, net	6,006.20	5,787.80
Other property	8.3	7.3
Total property, plant and equipment, net	6,014.50	5,795.10
Other assets	'	'
Unamortized debt expense	14.8	16.1
Regulatory assets	293.1	382.6
Derivative assets	0.3	0.2
Other	4.6	6.2
Total other assets	312.8	405.1
Total assets	6,875.80	6,744.60
Current liabilities	'	'
Long-term debt due within one year	83.3	0
Notes payable	84	0
Accounts payable	226	188.6
Customer deposits	164.5	163
Regulatory liabilities	85.8	105.6
Derivative liabilities	0	14.1
Interest accrued	16.4	17.3
Taxes accrued	12.2	13.7
Other	12	11.8
Total current liabilities	684.2	514.1
Other liabilities	'	'
Deferred income taxes	1,114.30	980.9
Investment tax credits	9.4	9.7
Regulatory liabilities	631.4	631.4
Derivative liabilities	0.2	0.2
Other	308.1	409.4
Long-term debt, less amount due within one year	1,797.50	1,932.60
Total other liabilities	2,063.40	2,031.60
Commitments and Contingencies	'	'
Capital	'	'
Common equity	2,030.40	1,970.40
Retained earnings	308.1	304.6
Accumulated other comprehensive loss	-7.8	-8.7
Total capital	2,330.70	2,266.30
Total capitalization	4,128.20	4,198.90
Total liabilities and capital	6,857.80	6,744.60
Tampa Electric Company [Member] | Fuel [Member]	'	'
Inventories, at average cost	'	'
Utility inventories	93.7	89.1
Tampa Electric Company [Member] | Materials and Supplies [Member]	'	'
Inventories, at average cost	'	'
Utility inventories	76.8	72.4
Tampa Electric Company [Member] | Electric [Member]	'	'
Property, plant and equipment	'	'
Electric	6,934	6,654.50
Tampa Electric Company [Member] | Gas [Member]	'	'
Property, plant and equipment	'	'
Electric	$1,249.50	$1,171.90

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Allowance for uncollectibles	$4.70	$4.20
Common equity, shares authorized	400,000,000	400,000,000
Common equity, par value	$1	$1
Common equity, shares outstanding	217,300,000	216,600,000
Tampa Electric Company [Member]	'	'
Allowance for uncollectibles	$2	$1.50
Common equity, shares authorized	25,000,000	25,000,000
Common equity, shares outstanding	10	10

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	'	'	'
Regulated electric and gas (includes franchise fees and gross receipts taxes of $108.5 in 2013, $111.5 in 2012 and $109.3 in 2011)	$2,342.50	$2,377.40	$2,469.80
Unregulated	508.8	619.2	740.1
Total revenues	2,851.30	2,996.60	3,209.90
Expenses	'	'	'
Fuel	680.2	694.7	731.4
Purchased power	64.7	105.3	125.9
Cost of natural gas sold	142.2	155.7	210.4
Other	524.4	462.5	436.9
Operation and maintenance other expense	'	'	'
Mining related costs	419	461.1	574.1
Other	12.5	7.9	7.1
Depreciation and amortization	329.5	330.6	317.2
Taxes, other than income	215.1	222.3	223.7
Total expenses	2,387.60	2,440.10	2,626.70
Income from operations	463.7	556.5	583.2
Other income (expense)	'	'	'
Allowance for other funds used during construction	6.3	2.6	1
Other income	3.6	9.4	6.7
Loss on debt extinguishment	0	-1.2	0
Total other income	9.9	10.8	7.7
Interest charges	'	'	'
Interest expense	170.5	185	198
Allowance for borrowed funds used during construction	-3.6	-1.5	-0.6
Total interest charges	166.9	183.5	197.4
Income from continuing operations before provision for income taxes	306.7	383.8	393.5
Provision for income taxes	108.9	137.8	142.7
Net income from continuing operations	197.8	246	250.8
Discontinued operations	'	'	'
Income (loss) from discontinued operations	-0.2	-10.6	33.3
Provision for income taxes	-0.1	22.4	11.2
Income (loss) from discontinued operations, net	-0.1	-33	22.1
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.3	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	-0.1	-33.3	21.8
Net income attributable to TECO Energy	$197.70	$212.70	$272.60
Average common shares outstanding - Basic	215	214.3	213.6
Average common shares outstanding - Diluted	215.5	215	215.1
Earnings per share from continuing operations - Basic	$0.92	$1.14	$1.17
Earnings per share from continuing operations - Diluted	$0.92	$1.14	$1.17
Earnings per share from discontinued operations attributable to TECO Energy - Basic	$0	($0.15)	$0.10
Earnings per share from discontinued operations attributable to TECO Energy - Diluted	$0	($0.15)	$0.10
Earnings per share attributable to TECO Energy - Basic	$0.92	$0.99	$1.27
Earnings per share attributable to TECO Energy - Diluted	$0.92	$0.99	$1.27
Dividends paid per common share outstanding	$0.88	$0.88	$0.85

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Franchise fees and gross receipts taxes	$108.50	$111.50	$109.30

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Income And Comprehensive Income [Abstract]	'	'	'
Net income attributable to TECO Energy	$197.70	$212.70	$272.60
Other comprehensive income (loss), net of tax	'	'	'
Net unrealized gains (losses) on cash flow hedges	1.4	-4.2	-0.8
Amortization of unrecognized benefit costs and other	14.8	-4.8	-4.6
Recognized benefit costs due to settlement	1.6	0	0.6
Other comprehensive income (loss), net of tax	17.8	-9	-4.8
Comprehensive income attributable to TECO Energy	$215.50	$203.70	$267.80

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities	'	'	'
Net income	$197.70	$212.70	$272.60
Adjustments to reconcile net income to net cash from operating activities:	'	'	'
Depreciation and amortization	329.5	337.7	324.6
Deferred income taxes	110.4	136.9	146
Investment tax credits	-0.3	-0.3	-0.4
Allowance for other funds used during construction	-6.3	-2.6	-1
Non-cash stock compensation	13.5	12	9.1
(Gain) loss on sales of business/assets, pretax	-1.6	18.5	-0.5
Deferred recovery clauses	-6.2	-8.9	-9
Asset impairment, pretax	0	17.2	0
Receivables, less allowance for uncollectibles	-4.5	37.7	5.7
Inventories	1.1	-2.4	23.5
Prepayments and other current assets	-2.2	-2	-2.8
Taxes accrued	1.4	12.1	-5.7
Interest accrued	-1.3	-5.9	0.3
Accounts payable	35.9	-1.3	-42.6
Other	-8.5	-4.7	34.3
Cash flows from operating activities	658.6	756.7	754.1
Cash flows from investing activities	'	'	'
Capital expenditures	-532.4	-505.1	-454.1
Allowance for other funds used during construction	6.3	2.6	1
Net proceeds from sales of business/assets	4.3	194.4	3.5
Restricted cash	0	8.9	0
Other investing activities	0	0	14.4
Cash flows used in investing activities	-521.8	-299.2	-435.2
Cash flows from financing activities	'	'	'
Dividends	-191.2	-190.4	-183.2
Proceeds from the sale of common stock	6.7	3.9	7
Proceeds from long-term debt issuance	0	538.1	0
Repayment of long-term debt/Purchase in lieu of redemption	-51.6	-650.4	-153.6
Change in short-term debt	84	0	-12
Other financing activities	0	-2.2	-0.6
Cash flows used in financing activities	-152.1	-301	-342.4
Net (decrease) increase in cash and cash equivalents	-15.3	156.5	-23.5
Cash and cash equivalents at beginning of the year	200.5	44	67.5
Cash and cash equivalents at end of the year	185.2	200.5	44
Supplemental disclosure of cash flow information	'	'	'
Interest	161	188.4	191.6
Income taxes paid	1.8	7.2	9.4
Tampa Electric Company [Member]	'	'	'
Cash flows from operating activities	'	'	'
Net income	225.6	227.2	235.3
Adjustments to reconcile net income to net cash from operating activities:	'	'	'
Depreciation and amortization	290.3	288.2	270.5
Deferred income taxes	118.4	155.9	173.6
Investment tax credits	-0.3	-0.3	-0.4
Allowance for other funds used during construction	-6.3	-2.6	-1
(Gain) loss on sales of business/assets, pretax	0	-0.2	-0.3
Deferred recovery clauses	-6.2	-8.9	-9
Receivables, less allowance for uncollectibles	-13.8	1.6	47.8
Inventories	-9	4.1	12.6
Prepayments	-1	-1	-0.5
Taxes accrued	-34.3	-5.7	7.9
Interest accrued	-0.9	-8.3	1
Accounts payable	34.8	12.4	-42.2
Other	-1.8	5.2	29.4
Cash flows from operating activities	595.5	667.6	724.7
Cash flows from investing activities	'	'	'
Capital expenditures	-507.6	-459	-386.8
Allowance for other funds used during construction	6.3	2.6	1
Net proceeds from sale of assets	0.1	0.3	2.8
Cash flows used in investing activities	-501.2	-456.1	-383
Cash flows from financing activities	'	'	'
Dividends	-222.1	-228.3	-240.7
Proceeds from the sale of common stock	60	118	0
Proceeds from long-term debt issuance	0	538.1	0
Repayment of long-term debt/Purchase in lieu of redemption	-51.6	-608	-78.8
Change in short-term debt	84	0	-12
Cash flows used in financing activities	-129.7	-180.2	-331.5
Net (decrease) increase in cash and cash equivalents	-35.4	31.3	10.2
Cash and cash equivalents at beginning of the year	45.2	13.9	3.7
Cash and cash equivalents at end of the year	9.8	45.2	13.9
Supplemental disclosure of cash flow information	'	'	'
Interest	102.4	128.1	129
Income taxes paid	$56.40	($9.70)	($31.10)

Consolidated_Statements_of_Cap

Consolidated Statements of Capital (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Beginning Balance	$2,291.80		$2,267.20		$2,170.60
Net income	197.7		213		272.9
Other comprehensive income, after tax	17.8		-9		-4.8
Common stock issued	5.9		-2.9		1
Cash dividends declared	-191.2		-190.4		-183.2
Stock compensation expense	13.5		12		9.1
Noncontrolling - dividends	'		-0.3		-0.6
Tax benefits - stock compensation	'		2.8		2.2
Ending Balance	2,333.70		2,291.80		2,267.20
Noncontrolling - sale of business	'		-0.6		'
Restricted stock - dividends	1.1		'		'
Tax short fall - stock compensation	-2.9		'		'
Common Stock [Member]	'		'		'
Beginning Balance	216.6		215.8		214.9
Beginning Balance, shares	216.6	[1]	215.8	[1]	214.9	[1]
Common stock issued	0.7		0.8		0.9
Common stock issued, shares	0.7	[1]	0.8	[1]	0.9	[1]
Ending Balance	217.3		216.6		215.8
Ending Balance, shares	217.3	[1]	216.6	[1]	215.8	[1]
Additional Paid-in Capital [Member]	'		'		'
Beginning Balance	1,564.50		1,553.40		1,542
Common stock issued	5.2		-3.7		0.1
Stock compensation expense	13.5		12		9.1
Tax benefits - stock compensation	'		2.8		2.2
Ending Balance	1,581.30		1,564.50		1,553.40
Restricted stock - dividends	1		'		'
Tax short fall - stock compensation	-2.9		'		'
Retained Earnings [Member]	'		'		'
Beginning Balance	541.7		519.4		430
Net income	197.7		212.7		272.6
Cash dividends declared	-191.2		-190.4		-183.2
Ending Balance	548.3		541.7		519.4
Restricted stock - dividends	0.1		'		'
Accumulated Other Comprehensive Income (Loss) [Member]	'		'		'
Beginning Balance	-31		-22		-17.2
Other comprehensive income, after tax	17.8		-9		-4.8
Ending Balance	-13.2		-31		-22
Noncontrolling Interest [Member]	'		'		'
Beginning Balance	'		0.6		0.9
Net income	'		0.3		0.3
Noncontrolling - dividends	'		-0.3		-0.6
Ending Balance	0		0		0.6
Noncontrolling - sale of business	'		($0.60)		'
[1]	(1) TECO Energy had a maximum of 400.0 million shares of $1 par value common stock authorized as of Dec. 31, 2013, 2012, 2011 and 2010.

Consolidated_Statements_of_Cap1

Consolidated Statements of Capital (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, except Per Share data, unless otherwise specified
Statement Of Stockholders Equity [Abstract]	'	'	'	'
Common equity, shares authorized	400	400	400	400
Common equity, par value	$1	$1	$1	$1

Consolidated_Statements_of_Inc2

Consolidated Statements of Income and Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	'	'	'
Total revenues	$2,851.30	$2,996.60	$3,209.90
Expenses	'	'	'
Total expenses	2,387.60	2,440.10	2,626.70
Fuel	680.2	694.7	731.4
Purchased power	64.7	105.3	125.9
Cost of natural gas sold	142.2	155.7	210.4
Other	524.4	462.5	436.9
Depreciation and amortization	329.5	330.6	317.2
Taxes, other than income	215.1	222.3	223.7
Income from operations	463.7	556.5	583.2
Other income	'	'	'
Allowance for other funds used during construction	6.3	2.6	1
Total other income	9.9	10.8	7.7
Interest charges	'	'	'
Interest on long-term debt	170.5	185	198
Allowance for borrowed funds used during construction	-3.6	-1.5	-0.6
Total interest charges	166.9	183.5	197.4
Income from continuing operations before provision for income taxes	306.7	383.8	393.5
Provision for income taxes	108.9	137.8	142.7
Net income attributable to TECO Energy	197.7	212.7	272.6
Other comprehensive income, net of tax	'	'	'
Net unrealized (loss) gain on cash flow hedges	1.4	-4.2	-0.8
Other comprehensive income (loss), net of tax	17.8	-9	-4.8
Comprehensive income	215.5	203.7	267.8
Tampa Electric Company [Member]	'	'	'
Revenues	'	'	'
Electric (includes franchise fees and gross receipts taxes of $88.0 in 2013, $91.1 in 2012 and $85.6 in 2011)	1,950.10	1,981	2,020.10
Gas (includes franchise fees and gross receipts taxes of $20.5 in 2013, $20.4 in 2012 and $23.7 in 2011)	392.7	397	450.5
Total revenues	2,342.80	2,378	2,470.60
Expenses	'	'	'
Total expenses	1,884.50	1,890	1,954.30
Fuel	680.2	694.7	731.4
Purchased power	64.7	105.3	125.9
Cost of natural gas sold	142.6	155.8	210.4
Other	523.6	462	436.4
Depreciation and amortization	290.3	288.2	270.5
Taxes, other than income	183.1	184	179.7
Income from operations	458.3	488	516.3
Other income	'	'	'
Allowance for other funds used during construction	6.3	2.6	1
Other income, net	5.1	4.1	2.9
Total other income	11.4	6.7	3.9
Interest charges	'	'	'
Interest on long-term debt	105	119.6	128.6
Other interest	3.9	7.7	11.5
Allowance for borrowed funds used during construction	-3.6	-1.5	-0.6
Total interest charges	105.3	125.8	139.5
Income from continuing operations before provision for income taxes	364.4	368.9	380.7
Provision for income taxes	138.8	141.7	145.4
Net income attributable to TECO Energy	225.6	227.2	235.3
Other comprehensive income, net of tax	'	'	'
Net unrealized (loss) gain on cash flow hedges	0.9	-4.1	0.7
Other comprehensive income (loss), net of tax	0.9	-4.1	0.7
Comprehensive income	$226.50	$223.10	$236

Consolidated_Statements_of_Inc3

Consolidated Statements of Income and Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Franchise fees and gross receipts taxes	$108.50	$111.50	$109.30
Tampa Electric Company [Member]	'	'	'
Franchise fees and gross receipts taxes	108.5	111.5	109.3
Tampa Electric Company [Member] | Electric [Member]	'	'	'
Franchise fees and gross receipts taxes	88	91.1	85.6
Tampa Electric Company [Member] | Gas [Member]	'	'	'
Franchise fees and gross receipts taxes	$20.50	$20.40	$23.70

Consolidated_Statements_of_Ret

Consolidated Statements of Retained Earnings (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Beginning Balance	$541.70	'	'
Add: Net income	197.7	212.7	272.6
Deduct: Cash dividends on capital stock - common	191.2	190.4	183.2
Ending Balance	548.3	541.7	'
Tampa Electric Company [Member]	'	'	'
Beginning Balance	304.6	305.7	311.1
Add: Net income	225.6	227.2	235.3
Retained Earning, Gross	530.2	532.9	546.4
Deduct: Cash dividends on capital stock - common	222.1	228.3	240.7
Ending Balance	$308.10	$304.60	$305.70

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Significant Accounting Policies	'
	1. Significant Accounting Policies
	The significant accounting policies for both utility and diversified operations are as follows:
	Principles of Consolidation and Basis of Presentation
	The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiaries do not have majority ownership or exercise control.
	For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).
	Use of Estimates
	The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.
	Restricted Cash
	Restricted cash of $8.7 million related to cash held in escrow for the 2003 sale of HPP, was released from escrow in 2012 upon maturity of debt financing that was held by the purchaser of HPP. There was no restricted cash at Dec. 31, 2013.
	Cash Equivalents
	Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
	Planned Major Maintenance
	Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.
	Tampa Electric and PGS expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.
	Depreciation
	Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:
		•		the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;
		•		the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.
	The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
	Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:
	Asset		Estimated Useful Lives
	Building and improvements		5 - 40 years
	Office equipment and furniture		3 - 30 years
	Vehicles, mining and other equipment		2 - 15 years
	Coal processing facilities		7 - 20 years
	Computer software		2 - 15 years
	Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $316.5 million, $309.3 million and $306.6 million, respectively.
	Allowance for Funds Used During Construction
	AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.
	Inventory
	TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis.
	Fuel Inventory		Dec. 31,		Dec. 31,
	(millions)		2013		2012
	TEC		$	93.7	$	89.1
	TECO Coal			25		34.5
	Total		$	118.7	$	123.6
	Regulatory Assets and Liabilities
	Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).
	Deferred Income Taxes
	TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).
	Investment Tax Credits
	ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
	Revenue Recognition
	TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.
	The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
	Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer.
	Revenues for energy marketing operations at TECO Energy Source are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2013, 2012 and 2011 were $23.1 million, $13.8 million and $2.5 million, respectively.
	Shipping and Handling
	TECO Coal includes the costs to ship product to customers in “Operation & maintenance other expense - Mining related costs” on the Consolidated Statements of Income which for the years ended Dec. 31, 2013, 2012 and 2011 were $8.2 million, $9.0 million and $16.6 million, respectively.
	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 Statements of Cash Flows.
	Revenues and Cost Recovery
	Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
	Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.
	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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively.
	Deferred Charges and Other Assets
	Deferred charges and other assets consist primarily of mining development costs amortized on a per ton basis and offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense.
	Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.
	Deferred Credits and Other Liabilities
Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2013 and 2012 ranged from 3.51% to 4.86% and 2.60% to 4.00%, respectively.
Stock-Based Compensation
TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.
Receivables and Allowance for Uncollectible Accounts
Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on Tampa Electric’s and PGS’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. TECO Coal’s receivables consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.
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.
Tampa Electric Company [Member]	'
Significant Accounting Policies	'
	1. Significant Accounting Policies
	The significant accounting policies are as follows:
	Basis of Accounting
	TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with GAAP in all material respects.
	The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance.
	TEC’s retail and wholesale businesses are regulated by the FPSC and related FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.
	Principles of Consolidation
	TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.
	For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).
	Planned Major Maintenance
	Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.
	Cash Equivalents
	Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
	Depreciation
	Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:
		•		the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;
		•		the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.
	The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $284.2 million, $275.1 million and $263.7 million, respectively.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
	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, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows.
	Allowance for Funds Used During Construction
	AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.
	Deferred Income Taxes
	TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.
	Investment Tax Credits
	ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
	Inventory
	TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.
	Revenue Recognition
	TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.
	The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
	Revenues and Cost Recovery
	Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
	Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.
	Accounting for Excise Taxes, Franchise Fees and Gross Receipts
	TEC is 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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.
	Reclassifications
	Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TEC’s net income in any period.

New_Accounting_Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements	'
	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.
	Offsetting Assets and Liabilities
	In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. The company has adopted this guidance as required. It had no effect on the company’s results of operations, financial position or cash flows.
Tampa Electric Company [Member]	'
New Accounting Pronouncements	'
	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.
	Offsetting Assets and Liabilities
	In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. TEC has adopted this guidance as required. It had no effect on TEC’s results of operations, financial position or cash flows.

Regulatory

Regulatory	12 Months Ended
	Dec. 31, 2013
Regulatory	'
	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 results for the first ten months of 2013, and all of 2012 and 2011, 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 provided for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requested certain changes to existing rate schedules, as well as the adoption of new rate designs.
	On Sept. 6, 2013, TEC and all of the intervenors in its Tampa Electric division base rate proceeding filed with the FPSC a joint motion for the FPSC to approve a stipulation and settlement agreement, which would resolve all matters in Tampa Electric’s pending base rate proceeding.
	This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
	On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved Tampa Electric’s base rate proceeding.
	Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.
	Storm Damage Cost Recovery
	Prior to the above mentioned stipulation and settlement agreement, Tampa Electric was accruing $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 $56.1 million and $50.4 million as of Dec. 31, 2013 and 2012, respectively. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to the level as of Oct. 31, 2013.
	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 Dec. 31, 2013 and 2012 are presented in the following table:
	Regulatory Assets and Liabilities
	(millions)		Dec. 31,		Dec. 31,
			2013		2012
	Regulatory assets:
	Regulatory tax asset (1)		$	67.4	$	67.2
	Other:
	Cost-recovery clauses			6.1		42.9
	Postretirement benefit asset			182.7		276.1
	Deferred bond refinancing costs (2)			8		9.2
	Environmental remediation			51.4		46.9
	Competitive rate adjustment			4.1		4.1
	Other			7.7		6.5
	Total other regulatory assets			260		385.7
	Total regulatory assets			327.4		452.9
	Less: Current portion			34.3		70.3
	Long-term regulatory assets		$	293.1	$	382.6
	Regulatory liabilities:
	Regulatory tax liability (1)		$	9.8	$	14.6
	Other:
	Cost-recovery clauses			54.5		73.9
	Transmission and delivery storm reserve			56.1		50.4
	Deferred gain on property sales (3)			2		3.4
	Provision for stipulation and other			0.8		1
	Accumulated reserve - cost of removal			594		593.7
	Total other regulatory liabilities			707.4		722.4
	Total regulatory liabilities			717.2		737
	Less: Current portion			85.8		105.6
	Long-term regulatory liabilities		$	631.4	$	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)		Dec. 31,		Dec. 31,
			2013		2012
	Clause recoverable (1)		$	10.2	$	47
	Components of rate base (2)			185.6		279.1
	Regulatory tax assets (3)			67.4		67.2
	Capital structure and other (3)			64.2		59.6
	Total		$	327.4	$	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.
Tampa Electric Company [Member]	'
Regulatory	'
	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 results for the first ten months of 2013, and all of 2012 and 2011, 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 provided for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requested certain changes to existing rate schedules, as well as the adoption of new rate designs.
	On Sept. 6, 2013, TEC and all of the intervenors in its Tampa Electric division base rate proceeding filed with the FPSC a joint motion for the FPSC to approve a stipulation and settlement agreement, which would resolve all matters in Tampa Electric’s pending base rate proceeding.
	This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
	On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved Tampa Electric’s base rate proceeding.
	Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.
	Storm Damage Cost Recovery
	Prior to the above mentioned stipulation and settlement agreement, Tampa Electric was accruing $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 $56.1 million and $50.4 million as of Dec. 31, 2013 and 2012, respectively. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to the level as of Oct. 31, 2013.
	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 Dec. 31, 2013 and 2012 are presented in the following table:
	Regulatory Assets and Liabilities
	(millions)		Dec. 31,		Dec. 31,
			2013		2012
	Regulatory assets:
	Regulatory tax asset (1)		$	67.4	$	67.2
	Other:
	Cost-recovery clauses			6.1		42.9
	Postretirement benefit asset			182.7		276.1
	Deferred bond refinancing costs (2)			8		9.2
	Environmental remediation			51.4		46.9
	Competitive rate adjustment			4.1		4.1
	Other			7.7		6.5
	Total other regulatory assets			260		385.7
	Total regulatory assets			327.4		452.9
	Less: Current portion			34.3		70.3
	Long-term regulatory assets		$	293.1	$	382.6
	Regulatory liabilities:
	Regulatory tax liability (1)		$	9.8	$	14.6
	Other:
	Cost-recovery clauses			54.5		73.9
	Transmission and delivery storm reserve			56.1		50.4
	Deferred gain on property sales (3)			2		3.4
	Provision for stipulation and other			0.8		1
	Accumulated reserve - cost of removal			594		593.7
	Total other regulatory liabilities			707.4		722.4
	Total regulatory liabilities			717.2		737
	Less: Current portion			85.8		105.6
	Long-term regulatory liabilities		$	631.4	$	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)		Dec. 31,		Dec. 31,
			2013		2012
	Clause recoverable (1)		$	10.2	$	47
	Components of rate base (2)			185.6		279.1
	Regulatory tax assets (3)			67.4		67.2
	Capital structure and other (3)			64.2		59.6
	Total		$	327.4	$	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.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
	4. Income Taxes
	In 2013, 2012 and 2011, TECO Energy recorded net tax provisions of $108.8 million, $160.2 million and $153.9 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes paid for income taxes as required for the alternative minimum tax, state income taxes, foreign income taxes and prior year audits in 2013, 2012 and 2011 were $1.8 million, $7.2 million and $9.4 million, respectively.
	Income tax expense consists of the following:
	Income Tax Expense (Benefit)
	(millions)		2013			2012			2011
	For the year ended Dec. 31,
	Continuing Operations
	Current income taxes
	Federal		$	2.2		$	15.7		$	0
	State			(3.5	)		1.1			0.9
	Deferred income taxes
	Federal			98.6			102.9			124
	State			11.9			18.4			18.2
	Amortization of investment tax credits			(0.3	)		(0.3	)		(0.4	)
	Income tax expense from continuing operations		$	108.9		$	137.8		$	142.7
	Discontinued Operations
	Current income taxes
	Federal		$	0		$	0		$	0
	Foreign			0			6.8			7.4
	State			0			0			0
	Deferred income taxes
	Federal			(0.1	)		14.9			4.4
	Foreign			0			0			(0.3	)
	State			0			0.7			(0.3	)
	Income tax expense from discontinued operations			(0.1	)		22.4			11.2
	Total income tax expense		$	108.8		$	160.2		$	153.9
	During 2013, TECO Energy increased its net operating loss carryforward. Total current income tax expense for the years ended Dec. 31, 2012 and 2011 was reduced by $13.6 million and $32.1 million, respectively, to reflect the benefits of operating loss carryforwards.
	The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:
	Effective Income Tax Rate
	(millions)		2013			2012			2011
	For the year ended Dec. 31,
	Income tax expense at the federal statutory rate of 35%		$	107.3		$	134.3		$	137.7
	Increase (decrease) due to:
	State income tax, net of federal income tax			5.5			12.7			12.4
	Equity portion of AFUDC			(2.2	)		(0.9	)		(0.4	)
	Valuation allowance			0			1.1			0
	Depletion			(3.7	)		(8.5	)		(9.1	)
	Other			2			(0.9	)		2.1
	Total income tax expense from continuing operations		$	108.9		$	137.8		$	142.7
	Income tax expense as a percent of income from continuing operations, before income taxes			35.5	%		35.9	%		36.3	%
	For the three years presented, the overall effective tax rate on continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes offset by depletion.
	As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2013 will be realized in future periods.
	The major components of the company’s deferred tax assets and liabilities recognized are as follows:
	Deferred Income Taxes
	(millions)
	As of Dec. 31,		2013			2012
	Deferred tax liabilities (1)
	Property related		$	1,164.20		$	1,023.30
	Deferred fuel			1.6			11.3
	Pension			52.8			43
	Total deferred tax liabilities			1,218.60			1,077.60
	Deferred tax assets (1)
	Alternative minimum tax credit carryforward			213			211.8
	Loss and credit carryforwards (2)			479.8			473.2
	Other postretirement benefits			68.9			68
	Other			113.2			113
	Total deferred tax assets			874.9			866
	Valuation allowance			0			(3.0	)
	Total deferred tax assets, net of valuation allowance			874.9			863
	Total deferred tax liability, net			343.7			214.6
	Less: Current portion of deferred tax asset			(100.3	)		(63.3	)
	Long-term portion of deferred tax liability, net		$	444		$	277.9
	-1	Certain property related assets and liabilities have been netted.
-2	As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2013 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.
At Dec. 31, 2013, the company had cumulative unused federal and state (Florida) NOLs for income tax purposes of $1,321.9 million and $392.6 million, respectively, expiring at various times between 2025 and 2028. In addition, the company has unused general business credits of $3.9 million expiring between 2026 and 2032. Due to the sale of the company’s remaining Guatemalan operations, unused foreign tax credits of $38.5 million have been reclassed to net operating loss. During 2013, the company’s available alternative minimum tax credit carryforward for tax purposes increased from $211.8 million to $213.0 million, reflecting the future AMT payable for the amendment of prior years’ federal income tax returns to claim a deduction for foreign tax paid. The alternative minimum tax credit may be used indefinitely to reduce federal income taxes.
The company’s consolidated balance sheet reflects loss carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through a reduction in income taxes payable.
The company establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. A state capital loss carryforward valuation allowance of $3.0 million was recorded as of Dec. 31, 2012. For the year ended Dec. 31, 2013, the company recorded a full valuation allowance release of $3.0 million due to the expiration of the state capital loss carryforward.
The company accounts for uncertain tax positions in accordance with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
Unrecognized Tax Benefits
(millions)		2013			2012
Balance at Jan. 1,		$	2.9		$	4.1
Decreases due to tax positions related to prior years			0			0
Decreases due to settlements with taxing authorities			0			0
Decreases due to expiration of statute of limitations			(2.9	)		0
Dispositions			0			(1.2	)
Balance at Dec. 31,		$	0		$	2.9
The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense – Other” in the Consolidated Statements of Income. In 2013, 2012 and 2011, the company recognized $(0.9) million, $0.3 million and $0.2 million, respectively, of pretax charges (benefits) for interest only. Additionally, the company had $0.0 million of interest accrued at Dec. 31, 2013 and $0.9 million of interest accrued at Dec. 31, 2012. No amounts have been recorded for penalties. As a result of the 2012 sale of TCAE, interest and penalties recorded on TCAE’s books for an uncertain tax position have been removed from the company’s unrecognized tax benefits (see Note 19).
The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. The federal income tax return for calendar year 2013 is part of the IRS’s Compliance Assurance Program. As a result, the IRS audit of such return is expected to be completed in 2014. 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 taxing authorities in major state jurisdictions include 2010 and forward. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.
Tampa Electric Company [Member]	'
Income Taxes	'
	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. For the three years presented, TEC’s effective tax rate differs from the statutory rate principally due to state income taxes, domestic production deduction and AFUDC equity benefit. The decrease in the 2013 effective tax rate compared to 2012 is principally due to equity portion of AFUDC.
	Income tax expense consists of the following components:
	Income Tax Expense (Benefit)
	(millions)		2013			2012			2011
	For the year ending Dec. 31,
	Current income taxes
	Federal		$	19.4		$	(19.5	)	$	(30.7	)
	State			1.3			5.6			2.9
	Deferred income taxes
	Federal			99.8			141.2			155.6
	State			18.6			14.7			18
	Amortization of investment tax credits			(0.3	)		(0.3	)		(0.4	)
	Total income tax expense		$	138.8		$	141.7		$	145.4
	The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:
	Effective Income Tax Rate
	(millions)		2013			2012			2011
	For the years ended Dec. 31,
	Income tax expense at the federal statutory rate of 35%		$	127.5		$	129.1		$	133.2
	Increase (decrease) due to
	State income tax, net of federal income tax			13			13.2			13.6
	Equity portion of AFUDC			(2.2	)		(0.9	)		(0.4	)
	Domestic production deduction			(0.6	)		(0.4	)		(1.5	)
	Other			1.1			0.7			0.5
	Total income tax expense on consolidated statements of income		$	138.8		$	141.7		$	145.4
	Income tax expense as a percent of income from continuing operations, before income taxes			38.1	%		38.4	%		38.2	%
	Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:
	Deferred Income Taxes
	(millions)		2013			2012
	As of Dec. 31,
	Deferred tax liabilities (1)
	Property related		$	1,166.40		$	1,016.20
	Deferred fuel			1.6			11.3
	Pension and postretirement benefits			70.5			106.6
	Pension			43.2			36.7
	Other			0			22.2
	Total deferred tax liabilities			1,281.70			1,193.00
	Deferred tax assets (1)
	Medical benefits			50.9			49
	Insurance reserves			29.1			31.1
	Investment tax credits			5.3			5.5
	Hedging activities			4.9			5.5
	Pension and postretirement benefits			70.5			106.6
	Unbilled revenue			12.1			14.8
	Capitalized energy conservation assistance costs			19.6			19.6
	Other			4.4			0
	Total deferred tax assets			196.8			232.1
	Total deferred tax liability, net			1,084.90			960.9
	Less: Current portion of deferred tax asset			(29.4	)		(20.0	)
	Long-term portion of deferred tax liability, net		$	1,114.30		$	980.9
	-1	Certain property related assets and liabilities have been netted.
	TEC accounts for uncertain tax positions as required by FASB accounting guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, TEC may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.
	As of Dec. 31, 2013 and 2012, TEC did not have a liability for unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2014. As of Dec. 31, 2013, TEC does not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.
	The IRS concluded its examination of federal income tax returns for the year 2012 in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and onward. The federal income tax return for calendar year 2013 is part of the IRS’s Compliance Assurance Program. As a result, the IRS audit of such return is expected to be completed in 2014. 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 2010 and onward. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

Employee_Postretirement_Benefi

Employee Postretirement Benefits	12 Months Ended
	Dec. 31, 2013
Employee Postretirement Benefits	'
	5. Employee Postretirement Benefits
	Pension Benefits
	TECO Energy has a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.
	The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.
	WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.
	In July 2012, the President signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under MAP-21.
	The qualified pension plan’s actuarial value of assets, including credit balance, was 96.7% of the Pension Protection Act funded target as of Jan. 1, 2013 and is estimated at 98.2% of the Pension Protection Act funded target as of Jan. 1, 2014.
	Amounts disclosed for pension benefits also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.
	Other Postretirement Benefits
	TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.
	MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.
	The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.
	In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2012. TEC is amortizing the regulatory asset over the remaining average service life of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.
	Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. Prior to this, the company received subsidy payments under Medicare Part D for its post-65 retiree prescription drug plan.
	Obligations and Funded Status
	TECO Energy recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC. The results of operations are not impacted. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in the Consolidated Balance Sheets for 2013 and 2012.
	Obligations and Funded Status		Pension Benefits								Other Benefits
	(millions)		2013				2012				2013			2012
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	715			$	646.4			$	230.3		$	216.5
	Service cost			18.2				17				2.5			2.4
	Interest cost			28.9				30.1				9.3			10.1
	Plan participants’ contributions			0				0				2.9			3.7
	Plan amendments			0				0				0			(5.2	)
	Actuarial loss (gain)			(50.4	)			54.7				(22.1	)		16.3
	Gross benefits paid			(43.1	)			(33.2	)			(15.0	)		(14.5	)
	Settlements			(2.6	)			0				0			0
	Federal subsidy on benefits paid			n/a				n/a				0.2			1
	Net benefit obligation at end of year		$	666			$	715			$	208.1		$	230.3
	Change in plan assets
	Fair value of plan assets at beginning of year		$	529.1			$	467.6			$	0		$	0
	Actual return on plan assets			63.7				57.9				0			0
	Employer contributions			45.9				36.8				11.9			9.8
	Plan participants’ contributions			0				0				2.9			3.7
	Settlements			(2.6	)			0				0			0
	Net benefits paid			(43.1	)			(33.2	)			(14.8	)		(13.5	)
	Fair value of plan assets at end of year		$	593			$	529.1			$	0		$	0
	Funded status
	Fair value of plan assets (1)		$	593			$	529.1			$	0		$	0
	Less: Benefit obligation (PBO/APBO)			666				715				208.1			230.3
	Funded status at end of year			(73.0	)			(185.9	)			(208.1	)		(230.3	)
	Unrecognized net actuarial loss			173.1				270.3				19.7			42.7
	Unrecognized prior service (benefit) cost			(0.4	)			(0.7	)			(0.7	)		(1.0	)
	Net amount required to be recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
	Amounts recognized in balance sheet
	Regulatory assets		$	139.6			$	216.5			$	43.2		$	59.6
	Accrued benefit costs and other current liabilities			(3.3	)			(5.3	)			(13.3	)		(13.1	)
	Deferred credits and other liabilities			(69.7	)			(180.6	)			(194.8	)		(217.2	)
	Accumulated other comprehensive loss (income), pretax			33.1				53.1				(24.2	)		(17.9	)
	Net amount recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
	-1	The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.
	Amounts recognized in accumulated other comprehensive income
			Pension Benefits								Other Benefits
	(millions)		2013				2012				2013			2012
	Net actuarial loss (gain)		$	32.7			$	52.7			$	(23.8	)	$	(17.2	)
	Prior service cost (credit)			0.4				0.4				(0.4	)		(0.7	)
	Amount recognized		$	33.1			$	53.1			$	(24.2	)	$	(17.9	)
	The accumulated benefit obligation for all defined benefit pension plans was $624.1 million at Dec. 31, 2013 and $664.7 million at Dec. 31, 2012. The projected benefit obligation for the other postretirement benefits plan was $208.1 million at Dec. 31, 2013 and $230.3 million at Dec. 31, 2012.
	Assumptions used to determine benefit obligations at Dec. 31:
			Pension Benefits								Other Benefits
			2013				2012				2013			2012
	Discount rate			5.118	%			4.196	%			5.096	%		4.18	%
	Rate of compensation increase - weighted			3.73	%			3.76	%			3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate			n/a				n/a				7.25	%		7.5	%
Ultimate rate			n/a				n/a				4.5	%		4.5	%
Year rate reaches ultimate			n/a				n/a				2025			2025
A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:
(millions)		1%				1%
		Increase				Decrease
Effect on postretirement benefit obligation		$	6.8			$	(6.1	)
The discount rate assumption used to determine the Dec. 31, 2013 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
		Pension Benefits											Other Benefits
Net periodic benefit cost
(millions)		2013				2012				2011			2013			2012			2011
Service cost		$	18.2			$	17			$	16		$	2.4		$	2.4		$	2.1
Interest cost			28.9				30.1				30.9			9.3			10.1			11.1
Expected return on plan assets			(38.4	)			(37.1	)			(38.4	)		0			0			0
Amortization of:
Actuarial loss			20.5				15.3				11.3			1			0.1			0.1
Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)		(0.3	)		0.8			0.8
Transition obligation			0				0				0			0			1.8			2.3
Settlement loss			1				0				0.9			0			0			0
Net periodic benefit cost		$	29.8			$	24.9			$	20.3		$	12.4		$	15.2		$	16.4
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and regulatory assets
(millions)		2013				2012				2011			2013			2012			2011
Prior service cost		$	0			$	0			$	0		$	0		$	(5.2	)	$	0
Net loss (gain)			(75.7	)			34				43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)			(21.5	)			(15.3	)		$	(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost			0.4				0.4				0.4			0.3			(0.8	)		(0.8	)
Transition obligation			0				0				0			0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets		$	(96.8	)		$	19.1			$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets		$	(67.0	)		$	44			$	51.8		$	(3.9	)	$	23.6		$	5.7
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $2.5 million and $0.1 million, respectively. The estimated prior service credit for the other postretirement benefit plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.2 million.
In addition, the estimated net loss and prior service credit for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $10.5 million and $0.5 million, respectively. There will be no remaining net loss for the other postretirement benefit plan that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.
Assumptions used to determine net periodic benefit cost for years ended Dec. 31:
		Pension Benefits											Other Benefits
		2013				2012				2011			2013			2012			2011
Discount rate			4.196	%			4.797	%			5.3	%		4.18	%		4.744	%		5.25	%
Expected long-term return on plan assets			7.5	%			7.5	%			7.75	%		n/a			n/a			n/a
Rate of compensation increase			3.76	%			3.83	%			3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Initial rate			n/a				n/a				n/a			7.5	%		7.75	%		8	%
Ultimate rate			n/a				n/a				n/a			4.5	%		4.5	%		4.5	%
Year rate reaches ultimate			n/a				n/a				n/a			2025			2025			2023
The discount rate assumption used to determine the 2013 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2013, TECO Energy’s pension plan experienced actual asset returns of approximately 12%.
The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.
A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:
(millions)		1%				1%
		Increase				Decrease
Effect on periodic cost		$	0.3			$	(0.3	)
Pension Plan Assets
Pension plan assets (plan assets) are primarily invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.
		Target Allocation		Actual Allocation, End of Year
Asset Category				2013				2012
Equity securities		48%-54%			54	%			55	%
Fixed income securities		46%-52%			46	%			45	%
Total		100%			100	%			100	%
The company reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company expects to take additional steps to more closely match plan assets with plan liabilities.
The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.
If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.
As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and Dec. 31, 2012.
Pension Plan Investments
(millions)		At Fair Value as of Dec. 31, 2013
		Level 1				Level 2				Level 3			Total
Accounts receivable		$	44.7			$	0			$	0		$	44.7
Accounts payable			(40.8	)			0				0			(40.8	)
Cash equivalents
Short term investment funds (STIFs)			7.9				0				0			7.9
Treasury bills (T bills)			0				0.3				0			0.3
Repurchase agreement			0				8.8				0			8.8
Commercial paper			0				0.4				0			0.4
Money markets			0				1.5				0			1.5
Total cash equivalents			7.9				11				0			18.9
Equity securities
Common stocks			91.6				0				0			91.6
American depository receipts (ADRs)			3				0				0			3
Real estate investment trusts (REITs)			1.7				0				0			1.7
Preferred stock			0				0.8				0			0.8
Mutual funds			172.6				0				0			172.6
Commingled fund			0				50				0			50
Total equity securities			268.9				50.8				0			319.7
Fixed income securities
Municipal bonds			0				7.3				0			7.3
Government bonds			0				35.7				0			35.7
Corporate bonds			0				19.6				0			19.6
Asset backed securities (ABS)			0				0.4				0			0.4
Mortgage-backed securities (MBS), net short sales			0				6.7				0			6.7
Collateralized mortgage obligations (CMOs)			0				2.3				0			2.3
Mutual fund			0				85.1				0			85.1
Commingled fund			0				94.1				0			94.1
Total fixed income securities			0				251.2				0			251.2
Derivatives
Short futures			0				0.2				0			0.2
Swaps			0				(0.9	)			0			(0.9	)
Purchased options (swaptions)			0				0.2				0			0.2
Written options (swaptions)			0				(0.4	)			0			(0.4	)
Total derivatives			0				(0.9	)			0			(0.9	)
Miscellaneous			0				0.2				0			0.2
Total		$	280.7			$	312.3			$	0		$	593
Pension Plan Investments
(millions)		At Fair Value as of Dec. 31, 2012
		Level 1				Level 2				Level 3			Total
Accounts receivable		$	64.8			$	0			$	0		$	64.8
Accounts payable			(72.8	)			0				0			(72.8	)
Cash equivalents
STIFs			9				0				0			9
T bills			0				0.6				0			0.6
Repurchase agreements			0				23.1				0			23.1
CDs			0				1.1				0			1.1
Commercial paper			0				0.9				0			0.9
Money markets			0				0.6				0			0.6
Total cash equivalents			9				26.3				0			35.3
Equity securities
Common stocks			125.3				0				0			125.3
ADRs			6.2				0				0			6.2
REITs			2				0				0			2
Preferred stocks			0				0.8				0			0.8
Equity mutual funds			153.4				0				0			153.4
Total equity securities			286.9				0.8				0			287.7
Fixed income securities
Municipal bonds			0				8				0			8
Government bonds			0				53				0			53
Corporate bonds			0				19.8				0			19.8
ABS			0				0.5				0			0.5
MBS			0				17.6				0			17.6
CMBS			0				0.3				0			0.3
CMOs			0				2.5				0			2.5
Fixed income mutual fund			0				63.7				0			63.7
Fixed income commingled fund			0				49.4				0			49.4
Total fixed income securities			0				214.8				0			214.8
Derivatives
Swaps			0				(0.5	)			0			(0.5	)
Purchased options (swaptions)			0				0.1				0			0.1
Written options (swaptions)			0				(0.4	)			0			(0.4	)
Total derivatives			0				(0.8	)			0			(0.8	)
Miscellaneous			0				0.1				0			0.1
Total		$	287.9			$	241.2			$	0		$	529.1
	•		The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
	•		The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.
	•		The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.
	•		The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
	•		T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
	•		The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
	•		The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
	•		The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.
	•		The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
	•		The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
	•		Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.
	•		Swaps are valued using benchmark yields, swap curves, and cash flow analyses.
	•		Options are valued using the bid-ask spread and the last price.
Other Postretirement Benefit Plan Assets
There are no assets associated with the company’s other postretirement benefits plan.
Contributions
The company’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $42.0 million and $35.5 million of contributions to this plan in 2013 and 2012, respectively, which met the minimum funding requirements for both 2013 and 2012. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2014 to be $47.5 million and expects to make contributions from 2015 to 2018 in the range of $4.0 to $48.0 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.
The SERP is funded annually to meet the benefit obligations. The company made contributions of $2.6 million and $1.3 million to this plan in 2013 and 2012, respectively. In 2014, the company expects to make a contribution of about $3.3 million to this plan.
The other postretirement benefits are funded annually to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2014, the company expects to make a contribution of about $13.3 million. Postretirement benefit levels are substantially unrelated to salary.
Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Expected Benefit Payments
(including projected service and net of employee contributions)
(millions)		Pension				Other
		Benefits				Postretirement
						Benefits
2014		$	53.5			$	13.3
2015			50.9				13.9
2016			55.3				14.6
2017			55.9				15.2
2018			58.3				15.7
2019-2023			298.6				81.9
Defined Contribution Plan
The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective April 2013, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31, 2013, 2012 and 2011, the company and its subsidiaries recognized expense totaling $11.3 million, $7.0 million and $9.0 million, respectively, related to the matching contributions made to this plan.
Black Lung Liability
TECO Coal is required by federal and state statutes to provide benefits to terminated, retired or (under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal is self-insured for black lung related claims. Annual expense is recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. At Dec. 31, 2013 and 2012, TECO Coal had an actuarially-determined black lung liability of $24.5 million and $27.1 million, respectively. TECO Coal recognized expense related to the black lung liability of $2.2 million, $1.8 million, and $1.7 million for 2013, 2012 and 2011, respectively.
Tampa Electric Company [Member]	'
Employee Postretirement Benefits	'
	5. Employee Postretirement Benefits
	Pension Benefits
	TEC is a participant in the comprehensive retirement plans of TECO Energy, including a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.
	The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.
	WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.
	In July 2012, the President signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under MAP-21.
	The qualified pension plan’s actuarial value of assets, including credit balance, was 96.7% of the Pension Protection Act funded target as of Jan. 1, 2013 and is estimated at 98.2% of the Pension Protection Act funded target as of Jan. 1, 2014.
	Amounts disclosed for pension benefits also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.
	Other Postretirement Benefits
	TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.
	MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.
	The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.
	In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. This amount was trued up in 2012. TEC is amortizing the regulatory asset over the remaining average service life of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.
	Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. Prior to this, the company received subsidy payments under Medicare Part D for its post-65 retiree prescription drug plan.
	Obligations and Funded Status
	TEC recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in TECO Energy’s Consolidated Balance Sheets for 2013 and 2012.
	TECO Energy		Pension Benefits								Other Benefits
	Obligations and Funded Status
	(millions)		2013				2012				2013			2012
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	715			$	646.4			$	230.3		$	216.5
	Service cost			18.2				17				2.5			2.4
	Interest cost			28.9				30.1				9.3			10.1
	Plan participants’ contributions			0				0				2.9			3.7
	Plan amendments			0				0				0			(5.2	)
	Actuarial loss (gain)			(50.4	)			54.7				(22.1	)		16.3
	Gross benefits paid			(43.1	)			(33.2	)			(15.0	)		(14.5	)
	Settlements			(2.6	)			0				0			0
	Federal subsidy on benefits paid			n/a				n/a				0.2			1
	Net benefit obligation at end of year		$	666			$	715			$	208.1		$	230.3
	Change in plan assets
	Fair value of plan assets at beginning of year		$	529.1			$	467.6			$	0		$	0
	Actual return on plan assets			63.7				57.9				0			0
	Employer contributions			45.9				36.8				11.9			9.8
	Plan participants’ contributions			0				0				2.9			3.7
	Settlements			(2.6	)			0				0			0
	Gross benefits paid			(43.1	)			(33.2	)			(14.8	)		(13.5	)
	Fair value of plan assets at end of year		$	593			$	529.1			$	0		$	0
	Funded status
	Fair value of plan assets (1)		$	593			$	529.1			$	0		$	0
	Less: Benefit obligation (PBO/APBO)			666				715				208.1			230.3
	Funded status at end of year			(73.0	)			(185.9	)			(208.1	)		(230.3	)
	Unrecognized net actuarial loss			173.1				270.3				19.7			42.7
	Unrecognized prior service (benefit) cost			(0.4	)			(0.7	)			(0.7	)		(1.0	)
	Unrecognized net transition obligation			0				0				0			0
	Net amount required to be recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
	Amounts recognized in balance sheet
	Regulatory assets		$	139.6			$	216.5			$	43.2		$	59.6
	Accrued benefit costs and other current liabilities			(3.3	)			(5.3	)			(13.3	)		(13.1	)
	Deferred credits and other liabilities			(69.7	)			(180.6	)			(194.8	)		(217.2	)
	Accumulated other comprehensive loss (income), pretax			33.1				53.1				(24.2	)		(17.9	)
	Net amount recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
	-1	The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.
	Tampa Electric Company		Pension Benefits								Other Benefits
	Amounts recognized in balance sheet
	(millions)		2013				2012				2013			2012
	Regulatory assets		$	139.6			$	216.5			$	43.2		$	59.6
	Accrued benefit costs and other current liabilities			(0.9	)			(0.9	)			(10.8	)		(10.6	)
	Deferred credits and other liabilities			(50.1	)			(139.8	)			(158.3	)		(174.2	)
			$	88.6			$	75.8			$	(125.9	)	$	(125.2	)
	The accumulated benefit obligation for TECO Energy Consolidated defined benefit pension plans was $624.1 million at Dec. 31, 2013 and $664.7 million at Dec. 31, 2012. The projected benefit obligation for the other postretirement benefits plan was $208.1 million at Dec. 31, 2013 and $230.3 million at Dec. 31, 2012.
	Assumptions used to determine benefit obligations at Dec. 31:
			Pension Benefits								Other Benefits
		2013				2012				2013			2012
Discount rate			5.118	%			4.196	%			5.096	%		4.18	%
Rate of compensation increase-weighted average			3.73	%			3.76	%			3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate			n/a				n/a				7.25	%		7.5	%
Ultimate rate			n/a				n/a				4.5	%		4.5	%
Year rate reaches ultimate			n/a				n/a				2025			2025
A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:
(millions)		1% Increase				1% Decrease
Effect on postretirement benefit obligation		$	5.6			$	(5.0	)
The discount rate assumption used to determine the Dec. 31, 2013 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
Components of TECO Energy Consolidated Net Periodic Benefit Cost
		Pension Benefits											Other Benefits
(millions)		2013				2012				2011			2013			2012			2011
Service cost		$	18.2			$	17			$	16		$	2.4		$	2.4		$	2.1
Interest cost			28.9				30.1				30.9			9.3			10.1			11.1
Expected return on plan assets			(38.4	)			(37.1	)			(38.4	)		0			0			0
Amortization of:
Actuarial loss			20.5				15.3				11.3			1			0.1			0.1
Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)		(0.3	)		0.8			0.8
Transition obligation			0				0				0			0			1.8			2.3
Settlement loss			1				0				0.9			0			0			0
Net periodic benefit cost		$	29.8			$	24.9			$	20.3		$	12.4		$	15.2		$	16.4
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets
(millions)		2013				2012				2011			2013			2012			2011
Prior service cost		$	0			$	0			$	0		$	0		$	(5.2	)	$	0
Net loss (gain)			(75.7	)			34				43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)			(21.5	)			(15.3	)			(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost			0.4				0.4				0.4			0.3			(0.8	)		(0.8	)
Transition obligation			0				0				0			0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets		$	(96.8	)		$	19.1			$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total Recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets		$	(67.0	)		$	44			$	51.8		$	(3.9	)	$	23.6		$	5.7
TEC’s portion of the net periodic benefit costs for pension benefits was $21.7 million, $18.3 million and $13.1 million for 2013, 2012 and 2011, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $10.0 million, $12.4 million and $10.0 million for 2013, 2012 and 2011, respectively.
The estimated net loss and prior service credit for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year are $10.5 million and $0.5 million, respectively. There will be no remaining net loss for the other postretirement benefit plan that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.
Assumptions used to determine net periodic benefit cost for years ended Dec. 31:
		Pension Benefits											Other Benefits
		2013				2012				2011			2013			2012			2011
Discount rate			4.196	%			4.797	%			5.3	%		4.18	%		4.744	%		5.25	%
Expected long-term return on plan assets			7.5	%			7.5	%			7.75	%		n/a			n/a			n/a
Rate of compensation increase			3.76	%			3.83	%			3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Immediate rate			n/a				n/a				n/a			7.5	%		7.75	%		8	%
Ultimate rate			n/a				n/a				n/a			4.5	%		4.5	%		4.5	%
Year rate reaches ultimate			n/a				n/a				n/a			2025			2025			2023
The discount rate assumption used to determine the 2013 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2013, TECO Energy’s pension plan experienced actual asset returns of approximately 12%.
The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.
A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:
(millions)		1% Increase				1% Decrease
Effect on periodic cost		$	0.2			$	(0.2	)
Pension Plan Assets
Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.
		Target Allocation		Actual Allocation, End of Year
Asset Category				2013				2012
Equity securities		48%-54%			54	%			55	%
Fixed income securities		46%-52%			46	%			45	%
Total		100%			100	%			100	%
TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy, Inc. expects to take additional steps to more closely match plan assets with plan liabilities.
The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.
If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.
As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and 2012.
Pension Plan Investments
(millions)		At Fair Value as of Dec. 31, 2013
		Level 1				Level 2				Level 3			Total
Accounts receivable		$	44.7			$	0			$	0		$	44.7
Accounts payable			(40.8	)			0				0			(40.8	)
Cash equivalents
STIFs			7.9				0				0			7.9
T bills			0				0.3				0			0.3
Repurchase agreements			0				8.8				0			8.8
Commercial paper			0				0.4				0			0.4
Money markets			0				1.5				0			1.5
Total cash equivalents			7.9				11				0			18.9
Equity securities
Common stocks			91.6				0				0			91.6
ADRs			3				0				0			3
REITs			1.7				0				0			1.7
Preferred stock			0				0.8				0			0.8
Mutual funds			172.6				0				0			172.6
Commingled fund			0				50				0			50
Total equity securities			268.9				50.8				0			319.7
Fixed income securities
Municipal bonds			0				7.3				0			7.3
Government bonds			0				35.7				0			35.7
Corporate bonds			0				19.6				0			19.6
ABS			0				0.4				0			0.4
MBS, net short sales			0				6.7				0			6.7
CMOs			0				2.3				0			2.3
Mutual funds			0				85.1				0			85.1
Commingled fund			0				94.1				0			94.1
Total fixed income securities			0				251.2				0			251.2
Derivatives
Short futures			0				0.2				0			0.2
Swaps			0				(0.9	)			0			(0.9	)
Purchased options (swaptions)			0				0.2				0			0.2
Written options (swaptions)			0				(0.4	)			0			(0.4	)
Total derivatives			0				(0.9	)			0			(0.9	)
Miscellaneous			0				0.2				0			0.2
Total		$	280.7			$	312.3			$	0		$	593
Pension Plan Investments
(millions)		At Fair Value as of Dec. 31, 2012
		Level 1				Level 2				Level 3			Total
Accounts receivable		$	64.8			$	0			$	0		$	64.8
Accounts payable			(72.8	)			0				0			(72.8	)
Cash equivalents
STIFs			9				0				0			9
T bills			0				0.6				0			0.6
Repurchase agreements			0				23.1				0			23.1
CDs			0				1.1				0			1.1
Commercial paper			0				0.9				0			0.9
Money markets			0				0.6				0			0.6
Total cash equivalents			9				26.3				0			35.3
Equity securities
Common stocks			125.3				0				0			125.3
ADRs			6.2				0				0			6.2
REITs			2				0				0			2
Preferred stocks			0				0.8				0			0.8
Equity mutual funds			153.4				0				0			153.4
Total equity securities			286.9				0.8				0			287.7
Fixed income securities
Municipal bonds			0				8				0			8
Government bonds			0				53				0			53
Corporate bonds			0				19.8				0			19.8
ABS			0				0.5				0			0.5
MBS			0				17.6				0			17.6
CMBS			0				0.3				0			0.3
CMOs			0				2.5				0			2.5
Fixed income mutual fund			0				63.7				0			63.7
Fixed income commingled fund			0				49.4				0			49.4
Total fixed income securities			0				214.8				0			214.8
Derivatives
Swaps			0				(0.5	)			0			(0.5	)
Purchased options (swaptions)			0				0.1				0			0.1
Written options (swaptions)			0				(0.4	)			0			(0.4	)
Total derivatives			0				(0.8	)			0			(0.8	)
Miscellaneous			0				0.1				0			0.1
Total		$	287.9			$	241.2			$	0		$	529.1
	•		The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
	•		The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.
	•		The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.
	•		The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
	•		T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
	•		The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
	•		The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
	•		The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.
	•		The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
	•		The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
	•		Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.
	•		Swaps are valued using benchmark yields, swap curves, and cash flow analyses.
	•		Options are valued using the bid-ask spread and the last price.
Other Postretirement Benefit Plan Assets
There are no assets associated with TECO Energy’s other postretirement benefits plan.
Contributions
TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy made $42.0 million of contributions to this plan in 2013 and $35.5 million in 2012, which met the minimum funding requirements for both 2013 and 2012. TEC’s portion of the contribution in 2013 was $33.5 million and in 2012 was $27.9 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TECO Energy estimates its contribution in 2014 to be $47.5 million, with TEC’s portion being $38.4 million. TECO Energy estimates it will make annual contributions from 2015 to 2018 ranging from $4.0 to $48.0 million per year based on current assumptions, with TEC’s portion to range from $3 million to $39 million. These amounts are in excess of the minimum funding required under ERISA guidelines.
The SERP is funded annually to meet the benefit obligations. TECO Energy made contributions of $2.6 million and $1.3 million to this plan in 2013 and 2012, respectively. TEC’s portion of the contributions in 2013 and 2012 were $1.0 million and $0.6 million, respectively. In 2014, TECO Energy expects to make a contribution of about $3.3 million to this plan. TEC’s portion of the expected contribution is about $0.9 million.
The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2014, TECO Energy expects to make a contribution of about $13.3 million. TEC’s portion of the expected contribution is $10.8 million. Postretirement benefit levels are substantially unrelated to salary.
Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Expected Benefit Payments - TECO Energy
(including projected service and net of employee contributions)						Other
		Pension				Postretirement
(millions)		Benefits				Benefits
2014		$	53.5			$	13.3
2015			50.9				13.9
2016			55.3				14.6
2017			55.9				15.2
2018			58.3				15.7
2019-2023			298.6				81.9
Defined Contribution Plan
TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Employer matching contributions are 60% of eligible participant contributions with additional incentive match of up to 40% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended Dec. 31, 2013, 2012 and 2011, TECO Energy and its subsidiaries recognized expense totaling $11.3 million, $7.0 million and $9.0 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled $9.1 million, $6.0 million and $5.8 million for 2013, 2012 and 2011, respectively.

ShortTerm_Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2013
Short-Term Debt	'
	6. Short-Term Debt
	At Dec. 31, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:
	Credit Facilities
			Dec. 31, 2013						Dec. 31, 2012
	(millions)		Credit		Borrowings		Letters		Credit		Borrowings		Letters
			Facilities		Outstanding (1)		of Credit		Facilities		Outstanding (1)		of Credit
							Outstanding						Outstanding
	Tampa Electric Company:
	5-year facility (2)		$	325	$	6	$	0.7	$	325	$	0	$	1.5
	1-year accounts receivable facility			150		78		0		150		0		0
	TECO Energy/TECO Finance:
	5-year facility (2)(3)			200		0		0		200		0		0
	Total		$	675	$	84	$	0.7	$	675	$	0	$	1.5
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.
	-3	TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
	At Dec. 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at Dec. 31, 2012.
	Tampa Electric Company Accounts Receivable Facility
	On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A., Inc. as Program Agent. The amendment extends the maturity date to Feb. 13, 2015 and makes certain other technical changes. Please refer to Note 24 for additional information.
	Amendments of TECO Energy/TECO Finance Credit Facility
	On Dec. 17, 2013, TECO Energy amended and restated its $200 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility). The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues with TECO Energy as Guarantor and its wholly-owned subsidiary, TECO Finance, as Borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (ix) makes other technical changes.
	The Fourth Amended and Restated Credit Agreement includes the changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. The Amendment was entered into to accommodate the acquisition of NMGI, as described in Note 22 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 previous 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 22 herein.
	Amendment of Tampa Electric Company Credit Facility
	On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.
Tampa Electric Company [Member]	'
Short-Term Debt	'
	6. Short-Term Debt
	At Dec. 31, 2013 and 2012, the following credit facilities and related borrowings existed:
	Credit Facilities
			Dec. 31, 2013						Dec. 31, 2012
	(millions)		Credit		Borrowings		Letters		Credit		Borrowings		Letters
			Facilities		Outstanding (1)		of Credit		Facilities		Outstanding (1)		of Credit
							Outstanding						Outstanding
	Tampa Electric Company:
	5-year facility (2)		$	325	$	6	$	0.7	$	325	$	0	$	1.5
	1-year accounts receivable facility			150		78		0		150		0		0
	Total		$	475	$	84	$	0.7	$	475	$	0	$	1.5
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.
	At Dec. 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at Dec. 31, 2012.
	Tampa Electric Company Accounts Receivable Facility
	On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A., Inc. as Program Agent. The amendment extends the maturity date to Feb. 13, 2015 and makes certain other technical changes. Please refer to Note 16 for additional information.
	Amendment of Tampa Electric Company Credit Facility
	On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-Term Debt	'
	7. Long-Term Debt
	At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 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 $3,442.2 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.
	TECO Finance is a 100% owned subsidiary of TECO Energy. TECO Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no other subsidiaries of TECO Energy guarantee TECO Finance’s securities.
	A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.
	TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2014 through 2018 and thereafter are as follows:
	Long-Term Debt Maturities
	As of Dec. 31, 2013		2014			2015			2016			2017		2018		Thereafter		Total
	(millions)																	Long-Term
																		Debt
	TECO Finance		$	0		$	191.2		$	250		$	300	$	0	$	300	$	1,041.20
	Tampa Electric			83.3			83.3			83.4			0		254.2		1,146.70		1,650.90
	PGS			0			0			0			0		50		181.7		231.7
	Total long-term debt maturities		$	83.3		$	274.5		$	333.4		$	300	$	304.2	$	1,628.40	$	2,923.80
	Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B
	On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On March 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.
	On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On March 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.
	On March 1, 2011, TEC purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA had issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously had been in auction rate mode and had been held by TEC since March 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to March 1, 2011.
	On March 26, 2008, TEC purchased in lieu of redemption $20 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 C.
	After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Dec. 31, 2013 to provide an opportunity to evaluate refinancing alternatives.
	Redemption of TECO Energy, Inc. 6.75% Notes due 2015
	On Dec. 5, 2012, TECO Energy redeemed $8.8 million of 6.75% Notes due May 15, 2015. The redemption price was equal to $1,141.86 per $1,000.00 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $1.2 million of premiums were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Statements of Cash Flows for the twelve months ended Dec. 31, 2012.
	Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002
	On Oct. 1, 2012, TEC redeemed $147.1 million of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, $60.7 million of the 2002 Bonds due Oct. 1, 2013 bore interest at 5.1% and $86.4 million of the 2002 Bonds due Oct. 1, 2023 bore interest at 5.5%.
	Issuance of Tampa Electric Company 2.60% Notes due 2022
	On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022 (the 2022 Notes). The 2022 Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2022 Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the 2022 Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after June 15, 2022, TEC may at its option redeem the 2022 Notes, in whole or in part, at 100% of the principal amount of the 2022 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.
	Issuance of Tampa Electric Company 4.10% Notes due 2042
	On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the 2042 Notes). The 2042 Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 2042 Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2042 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 2042 Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 2042 Notes, in whole or in part, at 100% of the principal amount of the 2042 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.
	Redemption of TECO Guatemala San José Project Notes
	On Dec. 19, 2012, in conjunction with the closing on the sale of its equity interests in the San José Power Station, TECO Energy utilized $25.3 million of the sale proceeds to repay the San José project notes.
	At Dec. 31, 2013 and 2012, TECO Energy had the following long-term debt outstanding:
	Long-Term Debt
	(millions) Dec. 31,				Due	2013			2012
	TECO Finance		Notes (1)(2)(3): 6.75% (effective rate of 6.9%)		2015	$	191.2		$	191.2
			4.0% (effective rate of 4.2%)		2016		250			250
			6.572% (effective rate of 7.3%)		2017		300			300
			5.15% (effective rate of 5.3%)		2020		300			300
	Total long-term debt of TECO Finance						1,041.20			1,041.20
	Tampa Electric		Installment contracts payable (4):
			5.65% Refunding bonds (effective rate of 5.9%)		2018		54.2			54.2
			Variable rate bonds repurchased in 2008 (5)		2020		0			0
			5.15% Refunding bonds repurchased in 2013 (effective rate of 5.4% for 2012) (6)		2025		0			51.6
			1.5% Term rate bonds repurchased in 2011 (7)		2030		0			0
			5.0% Refunding bonds repurchased in 2012 (8)		2034		0			0
			Notes (1): 6.25% (effective rate of 6.3%) (2)		2014-2016		250			250
			6.1% (effective rate of 6.0%)		2018		200			200
			5.4% (effective rate of 5.4%)		2021		231.7			231.7
			2.6% (effective rate of 2.7%)		2022		225			225
			6.55% (effective rate of 6.6%)		2036		250			250
			6.15% (effective rate of 6.2%)		2037		190			190
			4.1% (effective rate of 4.2%)		2042		250			250
	Total long-term debt of Tampa Electric						1,650.90			1,702.50
	PGS		Notes (1): 6.1% (effective rate of 7.0%)		2018		50			50
			5.4% (effective rate of 5.4%)		2021		46.7			46.7
			2.6% (effective rate of 2.7%)		2022		25			25
			6.15% (effective rate of 6.2%)		2037		60			60
			4.1% (effective rate of 4.2%)		2042		50			50
	Total long-term debt of PGS						231.7			231.7
	Total long-term debt of TECO Energy						2,923.80			2,975.40
	Unamortized debt discount, net						(2.7	)		(2.7	)
	Total carrying amount of long-term debt						2,921.10			2,972.70
	Less amount due within one year						83.3			0
	Total long-term debt					$	2,837.80		$	2,972.70
	-1	These securities are subject to redemption in whole or in part, at any time, at the option of the company.
-2	These long-term debt agreements contain various restrictive financial covenants.
-3	Guaranteed by TECO Energy.
-4	Tax-exempt securities.
-5	In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.
-6	In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.
-7	In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.
-8	In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.
Tampa Electric Company [Member]	'
Long-Term Debt	'
	7. Long-Term Debt
	A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.
	Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B
	On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On March 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.
	On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On March 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.
	On March 1, 2011, TEC purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA had issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously had been in auction rate mode and had been held by TEC since March 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to March 1, 2011.
	On March 26, 2008, TEC purchased in lieu of redemption $20 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 C.
	After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Dec. 31, 2013 to provide an opportunity to evaluate refinancing alternatives.
	Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002
	On Oct. 1, 2012, TEC redeemed $147.1 million of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (the 2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, $60.7 million of the 2002 Bonds due Oct. 1, 2013 bore interest at 5.1% and $86.4 million of the 2002 Bonds due Oct. 1, 2023 bore interest at 5.5%.
	Issuance of Tampa Electric Company 2.60% Notes due 2022
	On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022 (the 2022 Notes). The 2022 Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2022 Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the 2022 Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after June 15, 2022, TEC may at its option redeem the 2022 Notes, in whole or in part, at 100% of the principal amount of the 2022 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.
	Issuance of Tampa Electric Company 4.10% Notes due 2042
	On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the 2042 Notes). The 2042 Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 2042 Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2042 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 2042 Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 2042 Notes, in whole or in part, at 100% of the principal amount of the 2042 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Preferred_Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Preferred Stock	'
	8. Preferred Stock
	Preferred stock of TECO Energy – $1 par
	10 million shares authorized, none outstanding.
	Preference stock (subordinated preferred stock) of Tampa Electric – no par
	2.5 million shares authorized, none outstanding.
	Preferred stock of Tampa Electric – no par
	2.5 million shares authorized, none outstanding.
	Preferred stock of Tampa Electric – $100 par
	1.5 million shares authorized, none outstanding.

Common_Stock

Common Stock	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Common Stock	'
	9. Common Stock
	Stock-Based Compensation
	On May 5, 2010, the shareholders approved the 2010 Equity Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors.
	The 2010 Plan amended the 2004 Plan to reduce the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), remove the cap on shares available for stock grant, place various limitations on the terms of awards granted under the 2010 Plan, remove the ability to make awards to consultants of the company and reapprove the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code.
	The types of awards that can be granted under the 2010 Plan include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest between 0% and 150% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant.
	The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.
	The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.
	Assumptions		2013			2012			2011
	Assumptions applicable to performance-based restricted stock
	Risk-free interest rate			0.41	%		0.38	%		0.96	%
	Expected lives (in years)			3			3			3
	Expected stock volatility			19.04	%		20.99	%		34.61	%
	Dividend yield			4.83	%		4.78	%		4.48	%
	In 2013, 2012 and 2011, 0.7 million, 1.0 million and 0.8 million shares of restricted stock were granted, respectively, with weighted-average fair values per share of $17.21, $15.96 and $18.44 , respectively. The total fair market value of awards vesting during 2013, 2012 and 2011 was $3.5 million, $14.3 million and $13.4 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2013, there was $15.5 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted-average period of two years.
	The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.
	(millions)		2013			2012			2011
	Compensation costs (1)		$	13.5		$	12		$	9.1
	Income tax benefits (1)			5.2			4.6			3.5
	Excess tax benefits (2)			0			2.6			1.7
	-1	Reflected on the Consolidated Statements of Income.
	-2	Reflected as financing activities on the Consolidated Statements of Cash Flows.
	The aggregate intrinsic value of stock options exercised was $2.4 million, $0.3 million and $1.5 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively. Cash received from option exercises under all share-based payment arrangements was $6.7 million, $1.1 million and $5.0 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively. The income tax benefit realized from stock option exercises was $0.8 million, $0.1 million and $0.6 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively.
	A summary of non-vested shares of restricted stock is shown as follows:
	Nonvested Restricted Stock
			Time-Based Restricted						Performance-Based
			Stock (1)						Restricted Stock (1)
			Number of			Weighted -			Number of				Weighted-
			Shares			Avg. Grant			Shares				Avg. Grant
			(thousands)			Date			(thousands)				Date
						Fair Value							Fair Value
						(per share)							(per share)
	Nonvested balance at Dec. 31, 2012			592		$	18.04			1,490			$	17.13
	Granted			237			17.92			496				16.87
	Vested			(187	)		16.91			(434	)			17.2
	Forfeited			(4	)		17.99			(47	)			16.82
	Nonvested balance at Dec. 31, 2013			638		$	18.33			1,505			$	17.04
	-1	The weighted-average remaining contractual term of restricted stock is two years.
	Stock option transactions are summarized as follows:
	Stock Options
			Number of			Weighted-Avg.			Weighted-Avg.		Aggregate
			Shares			Option Price			Remaining		Intrinsic
			(thousands)			(per share)			Contractual		Value
									Term (years)		(millions)
	Outstanding balance at Dec. 31, 2012			2,087		$	15.05
	Granted			0			0
	Exercised			(507	)		13.22
	Cancelled			(13	)		18.87
	Outstanding balance at Dec. 31, 2013 (1)			1,567		$	15.62		2		$	2.6
	Exercisable at Dec. 31, 2013 (1)			1,567		$	15.62		2		$	2.6
	Available for future grant at Dec. 31, 2013			2,725
	-1	Option prices range from $12.01 to $19.01 per share.
	As of Dec. 31, 2013, the options outstanding and exercisable are summarized below:
	Range of		Option Shares			Weighted-Avg.			Weighted-Avg.
	Option Prices		(thousands)			Option Price			Remaining
	(per share)					(per share)			Contractual Life
	$12.01 - $13.56			331		$	13.1		1 Years
	$16.21 - $19.01			1,236		$	16.29		2 Years
	Total			1,567		$	15.62		2 Years
	Dividend Reinvestment Plan
	In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2013, 2012 and 2011, resulting in no increase in equity.

Other_Comprehensive_Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2013
Other Comprehensive Income	'
	10. Other Comprehensive Income
	TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:
	Other Comprehensive Income
	(millions)		Gross			Tax			Net
	2013
	Unrealized gain (loss) on cash flow hedges		$	1		$	(0.4	)	$	0.6
	Reclassification from AOCI to net income			1.3			(0.5	)		0.8
	Gain (Loss) on cash flow hedges			2.3			(0.9	)		1.4
	Amortization of unrecognized benefit costs and other			23.6			(8.8	)		14.8
	Recognized benefit costs due to settlement			2.6			(1.0	)		1.6
	Total other comprehensive income (loss)		$	28.5		$	(10.7	)	$	17.8
	2012
	Unrealized (loss) gain on cash flow hedges		$	(7.4	)	$	2.8		$	(4.6	)
	Reclassification from AOCI to net income			0.6			(0.2	)		0.4
	(Loss) Gain on cash flow hedges			(6.8	)		2.6			(4.2	)
	Amortization of unrecognized benefit costs and other (1)			(4.8	)		0			(4.8	)
	Total other comprehensive (loss) income		$	(11.6	)	$	2.6		$	(9.0	)
	2011
	Unrealized gain (loss) on cash flow hedges		$	1.8		$	(0.6	)	$	1.2
	Reclassification from AOCI to net income			(3.1	)		1.1			(2.0	)
	(Loss) Gain on cash flow hedges			(1.3	)		0.5			(0.8	)
	Amortization of unrecognized benefit costs and other			(7.9	)		3.3			(4.6	)
	Recognized benefit costs due to settlement			0.9			(0.3	)		0.6
	Total other comprehensive (loss) income		$	(8.3	)	$	3.5		$	(4.8	)
	Accumulated Other Comprehensive Loss
	(millions) As of Dec. 31,		2013			2012
	Unrecognized pension losses and prior service credits (2)		$	(20.5	)	$	(32.9	)
	Unrecognized other benefit gains, prior service costs and transition obligations (3)			15.1			11.1
	Net unrealized losses from cash flow hedges (4)			(7.8	)		(9.2	)
	Total accumulated other comprehensive loss		$	(13.2	)	$	(31.0	)
	-1	Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.
	-2	Net of tax benefit of $12.6 million and $20.1 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.
	-3	Net of tax expense of $9.1 million and $6.7 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.
	-4	Net of tax benefit of $4.9 million and $5.8 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.
Tampa Electric Company [Member]	'
Other Comprehensive Income	'
	8. Other Comprehensive Income
	TEC reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:
	Other Comprehensive Income
	(millions)		Gross			Tax			Net
	2013
	Unrealized gain (loss) on cash flow hedges		$	0		$	0		$	0
	Reclassification from AOCI to net income			1.4			(0.5	)		0.9
	Gain (Loss) on cash flow hedges			1.4			(0.5	)		0.9
	Total other comprehensive income (loss)		$	1.4		($	0.5	)	$	0.9
	2012
	Unrealized (loss) gain on cash flow hedges		($	8	)	$	3.1		($	4.9	)
	Reclassification from AOCI to net income			1.4			(0.6	)		0.8
	(Loss) Gain on cash flow hedges			(6.6	)		2.5			(4.1	)
	Total other comprehensive (loss) income		($	6.6	)	$	2.5		($	4.1	)
	2011
	Unrealized gain (loss) on cash flow hedges		$	0		$	0		$	0
	Reclassification from AOCI to net income			1.2			(0.5	)		0.7
	Gain (Loss) on cash flow hedges			1.2			(0.5	)		0.7
	Total other comprehensive income (loss)		$	1.2		($	0.5	)	$	0.7
	Accumulated Other Comprehensive Loss
	(millions) As of Dec. 31,		2013			2012
	Net unrealized losses from cash flow hedges (1)		($	7.8	)	($	8.7	)
	Total accumulated other comprehensive loss		($	7.8	)	($	8.7	)
	-1	Net of tax benefit of $4.9 million and $5.5 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	11. Earnings Per Share
	In accordance with accounting standards for the calculation of EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method.
	The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.
	(millions, except per share amounts)		2013			2012			2011 (1)
	Basic earnings per share
	Net income from continuing operations		$	197.8		$	246		$	250.8
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.8	)		(1.3	)
	Income before discontinued operations available to common shareholders - Basic		$	197.2		$	245.2		$	249.5
	Income (loss) from discontinued operations attributable to TECO Energy, net		($	0.1	)	($	33.3	)	$	21.8
	Amount allocated to nonvested participating shareholders			0			0.1			(0.1	)
	Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic		($	0.1	)	($	33.2	)	$	21.7
	Net income attributable to TECO Energy		$	197.7		$	212.7		$	272.6
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.7	)		(1.4	)
	Net income attributable to TECO Energy available to common shareholders - Basic		$	197.1		$	212		$	271.2
	Average common shares outstanding - Basic			215			214.3			213.6
	Earnings per share from continuing operations available to common shareholders - Basic		$	0.92		$	1.14		$	1.17
	Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic		$	0		($	0.15	)	$	0.1
	Earnings per share attributable to TECO Energy available to common shareholders - Basic		$	0.92		$	0.99		$	1.27
	Diluted earnings per share
	Net income from continuing operations		$	197.8		$	246		$	250.8
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.8	)		(1.3	)
	Income before discontinued operations available to common shareholders - Diluted		$	197.2		$	245.2		$	249.5
	Income (loss) from discontinued operations attributable to TECO Energy, net		($	0.1	)	($	33.3	)	$	21.8
	Amount allocated to nonvested participating shareholders			0			0.1			(0.1	)
	Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted		($	0.1	)	($	33.2	)	$	21.7
	Net income attributable to TECO Energy		$	197.7		$	212.7		$	272.6
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.7	)		(1.4	)
	Net income attributable to TECO Energy available to common shareholders - Diluted		$	197.1		$	212		$	271.2
	Unadjusted average common shares outstanding - Diluted			215			214.3			213.6
	Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net			0.5			0.7			1.5
	Average common shares outstanding - Diluted			215.5			215			215.1
	Earnings per share from continuing operations available to common shareholders - Diluted		$	0.92		$	1.14		$	1.17
	Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted		$	0		($	0.15	)	$	0.1
	Earnings per share attributable to TECO Energy available to common shareholders - Diluted		$	0.92		$	0.99		$	1.27
	Anti-dilutive shares			0			0.4			1.7
	-1	All prior periods presented reflect the classification of TECO Guatemala as discontinued operations (see Note 19).

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies	'
	12. 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. In December 2010, 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 against PGS. The Court’s order is now final and not appealable. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the 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 the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014, the attorneys for the plaintiffs withdrew from representation. A trial is expected sometime in 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.
	Environmental Protection Agency Section 114 Letter
	On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) 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 April 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 on July 23, 2013, the costs associated with which were not material to the financial results or financial position of TECO Energy.
	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 Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated 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.
	Long-Term Commitments
	TECO Energy has commitments under long-term leases, primarily for building space, capacity payments, office equipment and heavy equipment. Total rental expense for these leases, included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense – Mining related costs” and “Operation & maintenance other expense – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011, totaled $7.6 million, $8.1 million and $10.2 million, respectively. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:
	Future Minimum Lease and Capacity Payments
	(millions)		Capacity		Operating		Total
			Payments		Leases
	Year ended Dec. 31:
	2014		$	14.8	$	5	$	19.8
	2015			14.9		3.9		18.8
	2016			14.6		2.6		17.2
	2017			9.9		2.4		12.3
	2018			10.1		2.2		12.3
	Thereafter			0		13.4		13.4
	Total future minimum payments		$	64.3	$	29.5	$	93.8
	Guarantees and Letters of Credit
	TECO Energy accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:
		•		Initial recognition and initial measurement of a liability, and/or
		•		Disclosure of specific details of the guarantee.
	Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.
	Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
	A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2013 are as follows:
	Guarantees-TECO Energy
	(millions)						After (1)				Liabilities Recognized
	Guarantees for the Benefit of:		2014		2015-2018		2018		Total		at Dec. 31, 2013
	TECO Coal
	Fuel purchase related (2)		$	0.8	$	0.7	$	4	$	5.5	$	1.5
	Other subsidiaries
	Guaranty under sale agreement (3)			0		5		0		5		5
	Fuel sales and transportation (2)			10		0		91.8		101.8		0.1
	Total		$	10.8	$	5.7	$	95.8	$	112.3	$	6.6
	Letters of Credit-Tampa Electric Company
	(millions)						After (1)				Liabilities Recognized
	Letters of Credit for the Benefit of:		2014		2015-2018		2018		Total		at Dec. 31, 2013
	Tampa Electric (2)		$	0	$	0	$	0.7	$	0.7	$	0.1
	-1	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.
	-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 Dec. 31, 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. See Note 19 for additional information.
	Financial Covenants
	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. In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2013, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants.
Tampa Electric Company [Member]	'
Commitments and Contingencies	'
	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 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. In December 2010, 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 against PGS. The Court’s order is now final and not appealable. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the 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 the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014, the attorneys for the plaintiffs withdrew from representation. A trial is expected sometime in 2014.
	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.
	Environmental Protection Agency Section 114 Letter
	On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) 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 April 26, 2013 and has not received any response from the EPA on this matter.
	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 Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated 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.
	Long-Term Commitments
	TEC has commitments under long-term leases, primarily for building space, capacity payments, office equipment and heavy equipment. Total rental expense for these leases, included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011, totaled $2.3 million, $2.2 million and $2.2 million, respectively. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:
	Future Minimum Lease and Capacity Payments
	(millions)		Capacity		Operating		Total
			Payments		Leases
	Year ended Dec. 31:
	2014		$	14.8	$	2.3	$	17.1
	2015			14.9		2.3		17.2
	2016			14.6		2.2		16.8
	2017			9.9		2.2		12.1
	2018			10.1		2.2		12.3
	Thereafter			0		13.4		13.4
	Total future minimum payments		$	64.3	$	24.6	$	88.9
	Guarantees and Letters of Credit
	TEC accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:
		•		Initial recognition and initial measurement of a liability, and/or
		•		Disclosure of specific details of the guarantee.
	Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.
	Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
	At Dec. 31, 2013, TEC was not obligated under guarantees, but had $0.7 million of letters of credit outstanding.
	Letters of Credit - Tampa Electric Company
	(millions)		2014		2015-2018		After (1)		Total		Liabilities Recognized
	Letters of Credit for the Benefit of:						2018				at Dec. 31, 2013
	Tampa Electric (2)
	Letters of credit		$	0	$	0	$	0.7	$	0.7	$	0.1
	-1	These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2018.
	-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 Dec. 31, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.
	Financial Covenants
	In order to utilize their respective bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2013, TEC was in compliance with all required financial covenants.

Related_Parties

Related Parties	12 Months Ended
	Dec. 31, 2013
Related Parties	'
	13. Related Parties
	The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million, $1.3 million and $1.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively, to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2013, 2012 and 2011. No material balances were payable as of Dec. 31, 2013 or 2012.
Tampa Electric Company [Member]	'
Related Parties	'
	10. Related Party Transactions
	A summary of activities between TEC and its affiliates follows:
	Net transactions with affiliates:
	(millions)		2013		2012		2011
	Natural gas sales, net		$	18.3	$	11.7	$	0
	Administrative and general, net		$	27.2	$	23.4	$	17.5
	Amounts due from or to affiliates at Dec. 31,
	(millions)		2013		2012
	Accounts receivable (1)		$	1.3	$	4.7
	Accounts payable (1)			9.8		7.9
	Taxes receivable			54.9		22.1
	Taxes payable			0.4		3.2
	-1	Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
	TEC had certain transactions, in the ordinary course of business, with entities in which directors of TEC had interests. TEC paid legal fees of $1.7 million, $1.2 million and $1.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively, to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Information	'
	14. 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 Financial Statements of TECO Energy, but are included in determining reportable segments.
	Segment Information
	(millions)		Tampa		PGS		TECO			TECO			Other &			TECO
			Electric				Coal			Guatemala			Eliminations			Energy
	2013
	Revenues - external		$	1,949.60	$	392.7	$	496.2		$	0		$	12.8		$	2,851.30
	Sales to affiliates			0.9		0.8		0			0			(1.7	)		0
	Total revenues			1,950.50		393.5		496.2			0			11.1			2,851.30
	Depreciation and amortization			238.8		51.5		37.7			0			1.5			329.5
	Total interest charges (1)			91.8		13.5		5.5			0			56.1			166.9
	Internally allocated interest (1)			0		0		6.4			0			(6.4	)		0
	Provision for income taxes			116.9		21.9		(3.6	)		0			(26.3	)		108.9
	Net income from continuing operations			190.9		34.7		9			0			(36.8	)		197.8
	Discontinued operations attributable to TECO, net of tax			0		0		0			0			(0.1	)		(0.1	)
	Net income attributable to TECO Energy			190.9		34.7		9			0			(36.9	)		197.7
	Total assets			6,126.90		1,021.20		316.3	(3)		0			(16.4	)		7,448.00
	Capital expenditures			428.6		79		22.4			0			2.4			532.4
	2012
	Revenues - external		$	1,980.70	$	396.6	$	608.9		$	0		$	10.4		$	2,996.60
	Sales to affiliates			0.6		2.3		0			0			(2.9	)		0
	Total revenues			1,981.30		398.9		608.9			0			7.5			2,996.60
	Depreciation and amortization			237.6		50.6		41			0			1.4			330.6
	Total interest charges (1)			109.8		16		7.1			0			50.6			183.5
	Internally allocated interest (1)			0		0		6.8			0			(6.8	)		0
	Provision for income taxes			120.2		21.5		15.7			0			(19.6	)		137.8
	Net income from continuing operations			193.1		34.1		50.2			0			(31.4	)		246
	Discontinued operations attributable to TECO, net of tax			0		0		0			(29.3	)		(4.0	)		(33.3	)
	Net income attributable to TECO Energy			193.1		34.1		50.2			(29.3	)		(35.4	)		212.7
	Total assets			6,042.30		1,009.90		356.6	(3)		164.9			(238.8	)		7,334.90
	Capital expenditures			361.7		97.3		36.3			8.6			1.2			505.1
	2011
	Revenues - external		$	2,019.30	$	450.5	$	733		$	0		$	7.1		$	3,209.90
	Sales to affiliates			1.3		3		0			0			(4.3	)		0
	Total revenues			2,020.60		453.5		733			0			2.8			3,209.90
	Depreciation and amortization			222.1		48.4		45.3			0			1.4			317.2
	Total interest charges (1)			121.8		17.7		6.9			0			51			197.4
	Internally allocated interest (1)			0		0		6.7			0			(6.7	)		0
	Provision for income taxes			124.8		20.6		15.4			0			(18.1	)		142.7
	Net income from continuing operations			202.7		32.6		51.5			0			(36.0	)		250.8
	Discontinued operations attributable to TECO, net of tax (2)			0		0		0			22.4			(0.6	)		21.8
	Net income attributable to TECO Energy			202.7		32.6		51.5			22.4			(36.6	)		272.6
	Goodwill			0		0		0			55.4			0			55.4
	Total assets			5,925.90		932		385.2	(3)		304.1			(240.0	)		7,307.20
	Capital expenditures			314.9		71.9		56.6			7.2			3.5			454.1
	-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 2013 and 2012 were at a pretax rate of 6.00%, and for 2011 were at a pretax rate of 6.25%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.
	-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. See Note 19.
	-3	The carrying value of mineral rights as of Dec. 31, 2013, 2012 and 2011 was $12.1 million, $13.4 million and $15.0 million, respectively.
	Tampa Electric provides retail electric utility services to almost 700,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for almost 350,000 residential, commercial, industrial and electric power generation customers in the State of Florida.
	TECO Coal, through its wholly-owned subsidiaries, owns mineral rights and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia.
Tampa Electric Company [Member]	'
Segment Information	'
	11. Segment Information
	TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 700,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for almost 350,000 residential, commercial, industrial and electric power generation customers in the State of Florida.
			Tampa				Other &
	(millions)		Electric		PGS		Eliminations			TEC
	2013
	Revenues - external		$	1,950.10	$	392.7	$	0		$	2,342.80
	Sales to affiliates			0.4		0.8		(1.2	)		0
	Total revenues			1,950.50		393.5		(1.2	)		2,342.80
	Depreciation and amortization			238.8		51.5		0			290.3
	Total interest charges			91.8		13.5		0			105.3
	Provision for income taxes			116.9		21.9		0			138.8
	Net income			190.9		34.7		0			225.6
	Total assets			5,895.40		989.3		(8.9	)		6,875.80
	Capital expenditures			428.6		79		0			507.6
	2012
	Revenues - external		$	1,980.90	$	397.1	$	0		$	2,378.00
	Sales to affiliates			0.4		1.8		(2.2	)		0
	Total revenues			1,981.30		398.9		(2.2	)		2,378.00
	Depreciation and amortization			237.6		50.6		0			288.2
	Total interest charges			109.8		16		0			125.8
	Provision for income taxes			120.2		21.5		0			141.7
	Net income			193.1		34.1		0			227.2
	Total assets			5,760.40		970.9		13.3			6,744.60
	Capital expenditures			361.7		97.3		0			459
	2011
	Revenues - external		$	2,020.10	$	450.5	$	0		$	2,470.60
	Sales to affiliates			0.5		3		(3.5	)		0
	Total revenues			2,020.60		453.5		(3.5	)		2,470.60
	Depreciation and amortization			222.1		48.4		0			270.5
	Total interest charges			121.8		17.7		0			139.5
	Provision for income taxes			124.8		20.6		0			145.4
	Net income			202.7		32.6		0			235.3
	Total assets			5,678.00		888.4		(10.0	)		6,556.40
	Capital expenditures			314.9		71.9		0			386.8

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
	15. Asset Retirement Obligations
	TECO Energy accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.
	When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.
	TECO Energy has recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2013 and 2012, these obligations totaled $23.8 million and $23.6 million, respectively.
	As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.
	For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31, 2013 and 2012, these obligations totaled $4.8 million and $5.0 million, respectively.
	For the years ended Dec. 31, 2013, 2012 and 2011, TECO Energy recognized $1.4 million annually of accretion expense associated with AROs in “Depreciation and amortization” on the Consolidated Statements of Income. For the year ended Dec. 31, 2013, $1.4 million of liabilities settled resulted primarily from reclamation costs related to mine closures. For the year ended Dec. 31, 2012, $29.1 million of liabilities settled resulted primarily from asbestos abatement and other dismantling at the generating stations at Tampa Electric.
	Reconciliation of beginning and ending carrying amount of asset retirement obligations:
			Dec. 31,
	(millions)		2013			2012
	Beginning balance		$	28.6		$	53.8
	Additional liabilities			0.1			0.7
	Liabilities settled			(1.4	)		(29.1	)
	Accretion expense			1.4			1.4
	Revisions to estimated cash flows			(0.3	)		0
	Other (1)			0.2			1.8
	Ending balance		$	28.6		$	28.6
	-1	Accretion recorded as a deferred regulatory asset.
Tampa Electric Company [Member]	'
Asset Retirement Obligations	'
	12. Asset Retirement Obligations
	TEC accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.
	When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.
	As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.
	For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.
	For the year ended Dec. 31, 2012, $27.6 million of liabilities settled resulted primarily from asbestos abatement and other dismantling at the generating stations at Tampa Electric.
	Reconciliation of beginning and ending carrying amount of asset retirement obligations:
			Dec. 31,
	(millions)		2013			2012
	Beginning balance		$	5		$	30.8
	Additional liabilities			0.1			0
	Liabilities settled			(0.2	)		(27.6	)
	Revisions to estimated cash flows			(0.3	)		0
	Other (1)			0.2			1.8
	Ending balance		$	4.8		$	5
	-1	Accretion recorded as a deferred regulatory asset.

Accounting_for_Derivative_Inst

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2013
Accounting for Derivative Instruments and Hedging Activities	'
	16. Accounting for Derivative Instruments and Hedging Activities
	From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:
	•		To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS;
	•		To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates; and
	•		To limit the exposure to price fluctuations for physical purchases of fuel at TECO Coal.
	TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. 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 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 (see Note 17). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.
	The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).
	The 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 Dec. 31, 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 Dec. 31, 2013 and Dec. 31, 2012:
	Total Derivatives
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	9.7			$	0
	Long-term assets			0.3				0.2
	Total assets		$	10			$	0.2
	Current liabilities		$	0.1			$	14.6
	Long-term liabilities			0.2				0.6
	Total liabilities		$	0.3			$	15.2
	The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Dec. 31, 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				Gross				Net Amounts of
			of Recognized				Amounts Offset				Assets (Liabilities)
			Assets				on the Balance				Presented on the
			(Liabilities)				Sheet				Balance Sheet
	Dec. 31, 2013
	Description
	Derivative assets		$	10.5			$	(0.5	)		$	10
	Derivative liabilities		$	(0.8	)		$	0.5			$	(0.3	)
	Dec. 31, 2012
	Description
	Derivative assets		$	1			$	(0.8	)		$	0.2
	Derivative liabilities		$	(16.0	)		$	0.8			$	(15.2	)
	The following table presents the derivative cash flow hedges of diesel fuel contracts at Dec. 31, 2013 and 2012 to limit the exposure to changes in the market price for diesel fuel:
	Diesel Fuel Derivatives
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	0.2			$	0
	Long-term assets			0				0
	Total assets		$	0.2			$	0
	Current liabilities		$	0.1			$	0.5
	Long-term liabilities			0				0.4
	Total liabilities		$	0.1			$	0.9
	The following table presents the derivative hedges of natural gas contracts at Dec. 31, 2013 and 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 (1)
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	9.5			$	0
	Long-term assets			0.3				0.2
	Total assets		$	9.8			$	0.2
	Current liabilities		$	0			$	14.1
	Long-term liabilities			0.2				0.2
	Total liabilities		$	0.2			$	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 the cash flow hedges and previously settled interest rate swaps at Dec. 31, 2013 is a net loss of $7.8 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 table presents the fair values and locations of derivative instruments recorded on the balance sheet at Dec. 31, 2013 and 2012:
	Derivatives Designated As Hedging Instruments
			Asset Derivatives						Liability Derivatives
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2013		Location		Value				Location		Value
	Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets		$	0.2			Derivative liabilities		$	0.1
Long-term		Derivative assets			0			Derivative liabilities			0
Natural gas derivatives:
Current		Derivative assets			9.5			Derivative liabilities			0
Long-term		Derivative assets			0.3			Derivative liabilities			0.2
Total derivatives designated as hedging instruments				$	10					$	0.3
		Asset Derivatives						Liability Derivatives
(millions)		Balance Sheet		Fair				Balance Sheet		Fair
at Dec. 31, 2012		Location		Value				Location		Value
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets		$	0			Derivative liabilities		$	0.5
Long-term		Derivative assets			0			Derivative liabilities			0.4
Natural gas derivatives:
Current		Derivative assets			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 table presents the effect of energy related derivatives on the fuel recovery clause mechanism on the Consolidated Balance Sheets as of Dec. 31, 2013 and 2012:
Energy Related Derivatives
		Asset Derivatives						Liability Derivatives
(millions)		Balance Sheet		Fair				Balance Sheet		Fair
at Dec. 31, 2013		Location (1)		Value				Location (1)		Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities		$	9.5			Regulatory assets		$	0
Long-term		Regulatory liabilities			0.3			Regulatory assets			0.2
Total				$	9.8					$	0.2
(millions)		Balance Sheet		Fair				Balance Sheet		Fair
at Dec. 31, 2012		Location (1)		Value				Location (1)		Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities		$	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 Statements of Income.
Based on the fair value of the instruments at Dec. 31, 2013, net pretax gains of $9.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.
The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31:
		Amount of Gain/(Loss) on				Location of Gain/(Loss)		Gain/(Loss)
		Derivatives Recognized in				Reclassified From AOCI		Reclassified From
(millions)		OCI				Into Income		AOCI Into Income
Derivatives in Cash Flow Hedging Relationships			Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts:		$	0			Interest expense		($	0.9	)
Commodity contracts:
Diesel fuel derivatives			0.6			Mining related costs			0.1
Total		$	0.6					($	0.8	)
2012
Interest rate contracts:		($	4.9	)		Interest expense		($	0.8	)
Commodity contracts:
Diesel fuel derivatives			0.3			Mining related costs			0.4
Total		($	4.6	)				($	0.4	)
2011
Interest rate contracts:		$	0			Interest expense		($	0.7	)
Commodity contracts:
Diesel fuel derivatives			1.2			Mining related costs			2.7
Total		$	1.2					$	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 years ended Dec. 31, 2013, 2012 and 2011, all hedges were effective.
The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the years ended Dec. 31:
(millions)		Fair Value				Amount of				Amount of
		Asset/(Liability)				Gain/(Loss)				Gain/(Loss)
						Recognized				Reclassified From
						in OCI (1)				AOCI Into Income (1)
2013
Interest rate swaps		$	0			$	0			($	0.9	)
Diesel fuel derivatives			0.1				0.6				0.1
Total		$	0.1			$	0.6			($	0.8	)
2012
Interest rate swaps		$	0			($	4.9	)		($	0.8	)
Diesel fuel derivatives			(0.9	)			0.3				0.4
Total		($	0.9	)		($	4.6	)		($	0.4	)
2011
Interest rate swaps		$	0			$	0			($	0.7	)
Diesel fuel derivatives			(0.3	)			1.2				2.7
Total		($	0.3	)		$	1.2			$	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, 2014 for financial diesel fuel contracts and Dec. 31, 2015 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:
		Diesel Fuel Contracts								Natural Gas Contracts
(millions)		(Gallons)								(MMBTUs)
Year		Physical				Financial				Physical				Financial
2014			0				2				0				36.9
2015			0				0				0				7.6
Total			0				2				0				44.5
The company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with diesel fuel and natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.
It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Dec. 31, 2013, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were 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 risk in determining the fair value of counterparty positions. 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 in evaluating the potential impact of nonperformance risk to derivative positions. As of Dec. 31, 2013, substantially all positions with counterparties were net assets.
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 Dec. 31, 2013:
Contingent Features
(millions)		Fair Value				Derivative				Posted
		Asset/				Exposure				Collateral
		(Liability)				Asset/
						(Liability)
Credit Rating		($	0.1	)		($	0.1	)		$	0
Tampa Electric Company [Member]	'
Accounting for Derivative Instruments and Hedging Activities	'
	13. Accounting for Derivative Instruments and Hedging Activities
	From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:
		•		To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and
		•		To limit the exposure to interest rate fluctuations on debt securities.
	TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.
	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 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 (see Note 14). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.
	TEC applies 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).
	TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Dec. 31, 2013, all of TEC’s physical contracts qualify for the NPNS exception.
	The following table presents the derivative cash flow hedges of natural gas contracts at Dec. 31, 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 (1)
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	9.5			$	0
	Long-term assets			0.3				0.2
	Total assets		$	9.8			$	0.2
	Current liabilities		$	0			$	14.1
	Long-term liabilities			0.2				0.2
	Total liabilities		$	0.2			$	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 following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Dec. 31, 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				Gross				Net Amounts of
			of Recognized				Amounts Offset				Assets (Liabilities)
			Assets				on the Balance				Presented on the
			(Liabilities)				Sheet				Balance Sheet
	Dec. 31, 2013
	Description
	Derivative assets		$	10.3			$	(0.5	)		$	9.8
	Derivative liabilities		$	(0.7	)		$	0.5			$	(0.2	)
	Dec. 31, 2012
	Description
	Derivative assets		$	1			$	(0.8	)		$	0.2
	Derivative liabilities		$	(15.1	)		$	0.8			$	(14.3	)
	The ending balance in AOCI related to previously settled interest rate swaps at Dec. 31, 2013 is a net loss of $7.8 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.
	The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism on the Consolidated Balance Sheets as of Dec. 31, 2013 and 2012:
	Energy Related Derivatives
			Asset Derivatives						Liability Derivatives
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2013		Location (1)		Value				Location (1)		Value
	Commodity Contracts:
	Natural gas derivatives:
	Current		Regulatory liabilities		$	9.5			Regulatory assets		$	0
	Long-term		Regulatory liabilities			0.3			Regulatory assets			0.2
	Total				$	9.8					$	0.2
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2012		Location (1)		Value				Location (1)		Value
	Commodity Contracts:
	Natural gas derivatives:
	Current		Regulatory liabilities		$	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 Statements of Income.
	Based on the fair value of the instruments at Dec. 31, 2013, net pretax losses of $9.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.
	The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31, 2013, 2012 and 2011:
	(millions)		Location of Gain/(Loss) Reclassified		Amount of Gain/(Loss) Reclassified
			From AOCI Into Income		From AOCI Into Income
	For the years ended Dec. 31:				2013				2012				2011
	Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)
	Interest rate contracts:		Interest expense		($	0.9	)		($	0.8	)		($	0.7	)
	Total				($	0.9	)		($	0.8	)		($	0.7	)
	-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 years ended Dec. 31, 2013, 2012 and 2011, all hedges were effective.
The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2015 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:
(millions)		Natural Gas Contracts
		(MMBTUs)
Year		Physical				Financial
2014			0				36.9
2015			0				7.6
Total			0				44.5
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 Dec. 31, 2013, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were 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 risk in determining the fair value of counterparty positions. 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 in evaluating the potential impact of nonperformance risk to derivative positions. As of Dec. 31, 2013, substantially all positions with counterparties were net assets.
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. Substantially all of TEC’s open positions with counterparties as of Dec. 31, 2013 were asset positions.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements	'
	17. 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 Dec. 31, 2013 and 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 Dec. 31, 2013
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	9.8	$	0	$	9.8
	Diesel fuel swaps		0		0.2		0		0.2
	Total	$	0	$	10	$	0	$	10
	Liabilities
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Diesel fuel swaps		0		0.1		0		0.1
	Total	$	0	$	0.3	$	0	$	0.3
		At fair value as of Dec. 31, 2012
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Diesel fuel swaps		0		0		0		0
	Total	$	0	$	0.2	$	0	$	0.2
	Liabilities
	Natural gas swaps	$	0	$	14.3	$	0	$	14.3
	Diesel fuel swaps		0		0.9		0		0.9
	Total	$	0	$	15.2	$	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 16).
	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 Dec. 31, 2013, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were asset positions. There were no Level 3 assets or liabilities during the 2013 or 2012 fiscal years.
Tampa Electric Company [Member]	'
Fair Value Measurements	'
	14. Fair Value Measurements
	Items Measured at Fair Value on a Recurring Basis
	The following table sets 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 Dec. 31, 2013 and 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 Dec. 31, 2013
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	9.8	$	0	$	9.8
	Total	$	0	$	9.8	$	0	$	9.8
	Liabilities
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Total	$	0	$	0.2	$	0	$	0.2
		At fair value as of Dec. 31, 2012
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Total	$	0	$	0.2	$	0	$	0.2
	Liabilities
	Natural gas swaps	$	0	$	14.3	$	0	$	14.3
	Total	$	0	$	14.3	$	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 13).
	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 Dec. 31, 2013, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions. There were no Level 3 assets or liabilities during the 2013 or 2012 fiscal years.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2013
Variable Interest Entities	'
	18. Variable Interest Entities
	The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.
	TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.1 million, $75.8 million and $81.2 million, under these PPAs for the three years ended Dec. 31, 2013, 2012 and 2011, respectively.
	In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $46.6 million and $34.4 million for the two years ended Dec. 31, 2012 and 2011, respectively. 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 Balance Sheets, Statements of Income or Cash Flows.
Tampa Electric Company [Member]	'
Variable Interest Entities	'
	15. Variable Interest Entities
	The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.
	TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.1 million, $75.8 million and $81.2 million, under these PPAs for the three years ended Dec. 31, 2013, 2012 and 2011, respectively.
	In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $46.6 million and $34.4 million for the two years ended Dec. 31, 2012 and 2011, respectively. 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 Balance Sheets, Statements of Income or Cash Flows.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
Discontinued Operations And Disposal Groups [Abstract]	'
Discontinued Operations	'
	19. Discontinued Operations
	On Aug. 7, 2012, TECO Energy received an offer from Renewable Energy Investments Guatemala Limited (REIN), a wholly-owned subsidiary of Sur Eléctrica Holding Limited (SUR), to purchase the independent power projects in Guatemala and certain affiliated Guatemala companies. SUR and REIN are international business companies organized under the laws of the Commonwealth of the Bahamas. On Sept. 27, 2012, an indirect wholly-owned subsidiary of TECO Energy, Inc., TECO Guatemala Holdings II, LLC (TGH), entered into an equity purchase agreement with SUR, and two equity purchase agreements with REIN (the three equity purchase agreements are collectively referred to herein as the “PAs”). Pursuant to the PA with SUR, TGH agreed to sell all of its ownership interests in TPS Guatemala One, Ltd. (TPS GO) for $12.5 million, and pursuant to the PAs with REIN, it agreed to sell all of its ownership interests in (i) TPS San José International, Inc. (TPS SJI) for $213.5 million and (ii) TECO Guatemala Services, Ltd. (TGS) for $1.5 million (TPS GO, TPS SJI and TGS are collectively referred to herein as the Disposal Group). The companies in the Disposal Group are the ultimate parent companies of TCAE, CGESJ, TEMSA, and TPS Operaciones de Guatemala, Limitada (TPSO), the owner of certain local real estate assets and the employer of the local employees. The total purchase price for the Disposal Group under the PAs was $227.5 million.
	The sale of TPS GO, which owns 96.06% of TCAE, closed on Sept. 27, 2012. An affiliate of the party that controlled the remaining interest in TCAE (the “noncontrolling interest holder”) held certain contractual rights with respect to TEMSA and CGESJ, including a right of first offer. The noncontrolling interest holder was also granted the opportunity to purchase TGS since the operations of TPSO are integral to the operations of TEMSA and CGESJ. The noncontrolling interest holder exercised the right of first offer for TPS SJI and elected to purchase TGS by executing PAs similar to the PAs with REIN on Oct. 17, 2012 and Oct. 26, 2012, respectively. The sales of TPS SJI and TGS to the noncontrolling interest holder closed on Dec. 19, 2012.
	As a result of the PAs, the TECO Guatemala segment is accounted for as a discontinued operation at Dec. 31, 2013. The following table provides selected components of discontinued operations:
	Components of income from discontinued operations attributable to TECO Energy	Twelve months ended Dec. 31,
	(millions)	2013			2012			2011
	Revenues	$	0		$	114.2		$	133.5
	(Loss) income from operations		(0.2	)		27.7			33.7
	Loss on assets sold, including transaction costs		0			(38.3	)		(0.4	)
	Income (loss) from discontinued operations		(0.2	)		(10.6	)		33.3
	Provision (benefit) for income taxes		(0.1	)		22.4			11.2
	Income (loss) from discontinued operations, net		(0.1	)		(33.0	)		22.1
	Less: Income from discontinued operations attributable to noncontrolling interest		0			0.3			0.3
	Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
	The provision for income taxes line item includes an after-tax charge of $22.9 million in 2012 associated with foreign tax credits. The 2012 charge is a result of the sales of the Disposal Group which eliminate future foreign source income that would be required to utilize these credits.
	The PAs contain customary representations, warranties and covenants. The PAs also contain indemnification provisions subject to specified limitations as to time and amount, including an indemnification provision related to an uncertain tax position related to TCAE.
	On Dec. 19, 2013, the ICSID tribunal hearing TGH’s arbitration claim against the Republic of Guatemala under DR-CAFTA issued an award in the case. The ICSID tribunal unanimously found in favor of TGH and awarded damages of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the prime rate plus 2%. In addition, the tribunal ruled that Guatemala must reimburse TGH for approximately $7.5 million of the costs it incurred in pursuing the arbitration.
	The ICSID tribunal found that Guatemala breached its treaty obligation to grant TGH fair and equitable treatment under the terms of the DR-CAFTA, thereby causing damages to TGH for which it is entitled to compensation. In sum, the tribunal found that Guatemala’s repudiation of fundamental regulatory principles applying to the tariff review process was arbitrary and breached elementary standards of due process in administrative matters.
	Each party has 120 days from the date of the award to seek annulment of the decision. Pending the outcome of a potential annulment filing, results in 2013 do not reflect any benefit of this decision.

Goodwill_and_Asset_Impairments

Goodwill and Asset Impairments	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Goodwill and Asset Impairments	'
	20. Goodwill and Asset Impairments
	Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill with an indefinite life is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. The goodwill formerly on the company’s balance sheet related to the TECO Guatemala segment and arose from the purchase of multiple entities as a result of the company’s investments in the Alborada (held by TPS GO) and San José (held by TPS SJI) power plants. Since these reporting units were one level below the operating segment level, discrete cash flow information was available, and management regularly reviewed their operating results separately, these were the reporting unit level at which potential impairment was tested.
	Prior to the sales in 2012 (see Note 19), goodwill balances for the TPS GO and TPS SJI reporting units were written down to their implied fair value calculated using the offers from SUR and REIN. Although these were binding quoted prices, the fair value measurements were considered Level 2 measurements since the market was not active as defined by accounting standards (i.e. transactions for these assets were too infrequent to provide pricing information on an ongoing basis). Prior to receiving the offers from REIN and SUR, the fair values of TPS GO’s and TPS SJI’s goodwill amounts were calculated using the discounted cash flows appropriate for the business model of each reporting unit. Discounted cash flows were formerly the best estimates of fair value of the reporting units, since neither a sale nor a similar transaction was readily observed in the marketplace for many years due to an inactive market.
	The changes in the carrying amount of goodwill for the year ended Dec. 31, 2012 are represented in the following table:
	(millions)	TPS GO			TPS SJI			Total
	Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4
	Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)
	Goodwill written off upon sale, pretax		0			(40.2	)		(40.2	)
	Balance as of Dec. 31, 2012	$	0		$	0		$	0
	The Impairment losses, pretax and Goodwill written off upon sale, pretax amounts from the table above are recorded in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012.
	The company accounts for long-lived asset impairments in accordance with the accounting guidance for long-lived assets, which requires that long-lived assets held and used be tested for recoverability whenever events or changes in circumstances indicate that its carrying value may not be recoverable, and assets held for sale be recorded at the lower of its carrying amount or fair value less cost to sell. An asset is considered not recoverable if its carrying value exceeds the sum of its undiscounted expected cash flows. If it is determined that the carrying value is not recoverable and its carrying value exceeds its fair value, an impairment charge is made and the value of the asset is reduced to its fair value.
	Prior to the sale of TGS, the company recorded a long-lived asset pretax impairment charge of $2.0 million. This amount is recorded in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012. The fair value was calculated using the offer from REIN. Although it was a binding quoted price, the fair value measurement was considered a Level 2 measurement since the market was not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis).
	Additionally, in both 2012 and 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in each fourth quarter on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that are recoverable; therefore, no impairment charge was deemed necessary. Additionally, the company performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Dispositions	'
	21. Dispositions
	Sale of San José and Alborada
	On Sept. 27, 2012, TECO Guatemala entered into an agreement to sell all of the equity interests in the Alborada and San José power stations and their related facilities and operations in Guatemala for a total purchase price of $227.5 million in cash. The TECO Guatemala segment was accounted for as discontinued operations beginning in the third quarter of 2012. For more information regarding the sale, see Note 19.
	While TECO Energy and its subsidiaries will no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala in October 2010 under the DR – CAFTA. For more information on the claim, see Note 19.
	Net proceeds from the sale of all Guatemalan operations, after estimated transaction-related costs and the $25.3 million repayment of the San José power station project debt, were approximately $197.0 million. The sale resulted in an after-tax book loss and an after-tax charge associated with foreign tax credits of $28.6 million and $22.9 million, respectively.

Pending_Acquisition_of_New_Mex

Pending Acquisition of New Mexico Gas Company	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Pending Acquisition of New Mexico Gas Company	'
	22. 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 of 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 NMGC.
	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 expired without any further request for information. The company filed for approval from the New Mexico Public Regulation Commission on July 9, 2013.
	As previously reported, the company must obtain regulatory approvals from the NMPRC prior to consummating the pending acquisition of NMGC. On Jan. 10, 2014 a meeting was held with the joint applicants, hearing examiner, the NMPRC staff, and intervenors to establish an updated schedule. Based on this schedule, Staff and intervenor testimony is expected to occur on Feb. 28, with hearings to follow on March 24 – 28. The date for a final decision is yet to be determined. The company has indicated that the closing is likely to occur in the third quarter of 2014.
	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 (i) certain mergers, consolidations, liquidations and dissolutions of the company and certain subsidiaries, (ii) sales by the company and certain subsidiaries of all or a substantial part of its assets and, (iii) 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.
	TECO Energy Credit Agreement to be Assigned to and Assumed by NMGC
	In connection with the pending Acquisition, on Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility, pursuant to which it is the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy has no rights or obligations to borrow under the NMGC Credit Agreement, which it has entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, upon such closing, TECO Energy will designate NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder and Release Agreement duly executed by TECO Energy and NMGC, whereupon and upon the satisfaction of the other conditions precedent set forth in the NMGC Credit Agreement, (i) NMGC shall automatically become the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy shall cease to be a party to the NMGC Credit Agreement and shall have no further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) will allow NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, will allow NMGC to borrow funds at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) will allow NMGC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) will allow NMGC to request the lenders to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility.

Quarterly_Data_unaudited

Quarterly Data (unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Data (unaudited)	'
	23. Quarterly Data (unaudited)
	Financial data by quarter is as follows:
	(millions, except per share amounts)		Dec. 31		Sept. 30		June 30		March 31
	Quarter ended
	2013
	Revenues		$	688.4	$	765.9	$	735.9	$	661.1
	Income from operations			99.6		140.5		119.5		104.1
	Net income from continuing operations			42.1		62.9		51.6		41.2
	Net income attributable to TECO Energy			42		62.8		51.4		41.5
	EPS - Basic
	From continuing operations		$	0.2	$	0.29	$	0.24	$	0.19
	Attributable to TECO Energy			0.2		0.29		0.24		0.19
	EPS - Diluted
	From continuing operations		$	0.2	$	0.29	$	0.24	$	0.19
	Attributable to TECO Energy			0.2		0.29		0.24		0.19
	Dividends paid per common share outstanding		$	0.22	$	0.22	$	0.22	$	0.22
	Quarter ended		Dec. 31		Sept. 30		30-Jun		31-Mar
	2012
	Revenues (1)		$	688.4	$	858.6	$	752.5	$	697.1
	Income from operations (1)			109.5		183.1		149.1		114.8
	Net income from continuing operations (1)			45.6		90.2		65.6		44.6
	Net income attributable to TECO Energy			45.1		44		73.1		50.5
	EPS - Basic
	From continuing operations (1)		$	0.21	$	0.42	$	0.3	$	0.21
	Attributable to TECO Energy			0.21		0.2		0.34		0.24
	EPS - Diluted
	From continuing operations (1)		$	0.21	$	0.42	$	0.3	$	0.2
	Attributable to TECO Energy			0.21		0.2		0.34		0.23
	Dividends paid per common share outstanding		$	0.22	$	0.22	$	0.22	$	0.22
	-1	Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events	'
	24. Subsequent Events
	Tampa Electric Company Accounts Receivable Facility
	On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 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. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 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, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.
Tampa Electric Company [Member]	'
Subsequent Events	'
	16. Subsequent Events
	On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 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. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 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, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts and Reserves	12 Months Ended
	Dec. 31, 2013
Valuation And Qualifying Accounts [Abstract]	'
Schedule II - Valuation and Qualifying Accounts and Reserves	'
	SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	TECO ENERGY, INC.
	VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	For the Years Ended Dec. 31, 2013, 2012 and 2011
	(millions)
			Balance at		Additions						Balance at
			Beginning		Charged to		Other		Payments &		End of
			of Period		Income		Charges		Deductions (1)		Period
	Allowance for Uncollectible Accounts:
	2013		$	4.2	$	3.3	$	0	$	2.8	$	4.7
	2012		$	2.6	$	4.8	$	0	$	3.2	$	4.2
	2011		$	4.5	$	3.8	$	0	$	5.7	$	2.6
	-1	Write-off of individual bad debt accounts
	SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	TAMPA ELECTRIC COMPANY
	VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	For the Years Ended Dec. 31, 2013, 2012 and 2011
	(millions)
			Balance at		Additions						Balance at
			Beginning		Charged to		Other		Payments &		End of
			of Period		Income		Charges		Deductions (1)		Period
	Allowance for Uncollectible Accounts:
	2013		$	1.5	$	3.3	$	0	$	2.8	$	2
	2012		$	1.3	$	3.4	$	0	$	3.2	$	1.5
	2011		$	3.2	$	3.8	$	0	$	5.7	$	1.3
	-1	Write-off of individual bad debt accounts

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Principles of Consolidation and Basis of Presentation	'
	Principles of Consolidation and Basis of Presentation
	The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiaries do not have majority ownership or exercise control.
	For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).
Use of Estimates	'
	Use of Estimates
	The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.
Restricted Cash	'
	Restricted Cash
	Restricted cash of $8.7 million related to cash held in escrow for the 2003 sale of HPP, was released from escrow in 2012 upon maturity of debt financing that was held by the purchaser of HPP. There was no restricted cash at Dec. 31, 2013.
Cash Equivalents	'
	Cash Equivalents
	Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
Planned Major Maintenance	'
	Planned Major Maintenance
	Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.
	Tampa Electric and PGS expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.
Depreciation	'
	Depreciation
	Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:
		•		the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;
		•		the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.
	The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
	Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:
	Asset		Estimated Useful Lives
	Building and improvements		5 - 40 years
	Office equipment and furniture		3 - 30 years
	Vehicles, mining and other equipment		2 - 15 years
	Coal processing facilities		7 - 20 years
	Computer software		2 - 15 years
	Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $316.5 million, $309.3 million and $306.6 million, respectively.
Allowance for Funds Used During Construction	'
	Allowance for Funds Used During Construction
	AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.
Inventory	'
	Inventory
	TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis.
	Fuel Inventory		Dec. 31,		Dec. 31,
	(millions)		2013		2012
	TEC		$	93.7	$	89.1
	TECO Coal			25		34.5
	Total		$	118.7	$	123.6
Regulatory Assets and Liabilities	'
	Regulatory Assets and Liabilities
	Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).
Deferred Income Taxes	'
	Deferred Income Taxes
	TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).
Investment Tax Credits	'
	Investment Tax Credits
	ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
Revenue Recognition	'
	Revenue Recognition
	TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.
	The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
	Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer.
	Revenues for energy marketing operations at TECO Energy Source are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2013, 2012 and 2011 were $23.1 million, $13.8 million and $2.5 million, respectively.
Shipping and Handling	'
	Shipping and Handling
	TECO Coal includes the costs to ship product to customers in “Operation & maintenance other expense - Mining related costs” on the Consolidated Statements of Income which for the years ended Dec. 31, 2013, 2012 and 2011 were $8.2 million, $9.0 million and $16.6 million, respectively.
Cash Flows Related to Derivatives and Hedging Activities	'
	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 Statements of Cash Flows.
Revenues and Cost Recovery	'
	Revenues and Cost Recovery
	Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
	Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts	'
	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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively.
Deferred Charges and Other Assets	'
	Deferred Charges and Other Assets
	Deferred charges and other assets consist primarily of mining development costs amortized on a per ton basis and offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense.
	Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.
Deferred Credits and Other Liabilities	'
	Deferred Credits and Other Liabilities
	Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2013 and 2012 ranged from 3.51% to 4.86% and 2.60% to 4.00%, respectively.
Stock-Based Compensation	'
	Stock-Based Compensation
	TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.
Receivables and Allowance for Uncollectible Accounts	'
	Receivables and Allowance for Uncollectible Accounts
	Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on Tampa Electric’s and PGS’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. TECO Coal’s receivables consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.
Reclassifications	'
	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.
Tampa Electric Company [Member]	'
Cash Equivalents	'
	Cash Equivalents
	Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
Planned Major Maintenance	'
	Planned Major Maintenance
	Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.
Depreciation	'
	Depreciation
	Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:
		•		the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;
		•		the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.
	The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $284.2 million, $275.1 million and $263.7 million, respectively.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
Allowance for Funds Used During Construction	'
	Allowance for Funds Used During Construction
	AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.
Inventory	'
	Inventory
	TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.
Deferred Income Taxes	'
	Deferred Income Taxes
	TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.
Investment Tax Credits	'
	Investment Tax Credits
	ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
Revenue Recognition	'
	Revenue Recognition
	TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.
	The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
Cash Flows Related to Derivatives and Hedging Activities	'
	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, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows.
Revenues and Cost Recovery	'
	Revenues and Cost Recovery
	Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
	Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts	'
	Accounting for Excise Taxes, Franchise Fees and Gross Receipts
	TEC is 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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.
Reclassifications	'
	Reclassifications
	Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TEC’s net income in any period.
Basis of Accounting	'
	Basis of Accounting
	TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with GAAP in all material respects.
	The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance.
	TEC’s retail and wholesale businesses are regulated by the FPSC and related FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.
Principles of Consolidation	'
	Principles of Consolidation
	TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.
	For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Estimated Useful Lives of Depreciable Property	'
	Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:
	Asset	Estimated Useful Lives
	Building and improvements	5 - 40 years
	Office equipment and furniture	3 - 30 years
	Vehicles, mining and other equipment	2 - 15 years
	Coal processing facilities	7 - 20 years
	Computer software	2 - 15 years
Schedule of Fuel Inventory	'
	Fuel Inventory	Dec. 31,		Dec. 31,
	(millions)	2013		2012
	TEC	$	93.7	$	89.1
	TECO Coal		25		34.5
	Total	$	118.7	$	123.6

Regulatory_Tables

Regulatory (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Regulatory Assets and Regulatory Liabilities	'
	Details of the regulatory assets and liabilities as of Dec. 31, 2013 and 2012 are presented in the following table:
	Regulatory Assets and Liabilities
	(millions)		Dec. 31,		Dec. 31,
			2013		2012
	Regulatory assets:
	Regulatory tax asset (1)		$	67.4	$	67.2
	Other:
	Cost-recovery clauses			6.1		42.9
	Postretirement benefit asset			182.7		276.1
	Deferred bond refinancing costs (2)			8		9.2
	Environmental remediation			51.4		46.9
	Competitive rate adjustment			4.1		4.1
	Other			7.7		6.5
	Total other regulatory assets			260		385.7
	Total regulatory assets			327.4		452.9
	Less: Current portion			34.3		70.3
	Long-term regulatory assets		$	293.1	$	382.6
	Regulatory liabilities:
	Regulatory tax liability (1)		$	9.8	$	14.6
	Other:
	Cost-recovery clauses			54.5		73.9
	Transmission and delivery storm reserve			56.1		50.4
	Deferred gain on property sales (3)			2		3.4
	Provision for stipulation and other			0.8		1
	Accumulated reserve - cost of removal			594		593.7
	Total other regulatory liabilities			707.4		722.4
	Total regulatory liabilities			717.2		737
	Less: Current portion			85.8		105.6
	Long-term regulatory liabilities		$	631.4	$	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.
Regulatory Assets and Related Recovery Period	'
	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)		Dec. 31,		Dec. 31,
			2013		2012
	Clause recoverable (1)		$	10.2	$	47
	Components of rate base (2)			185.6		279.1
	Regulatory tax assets (3)			67.4		67.2
	Capital structure and other (3)			64.2		59.6
	Total		$	327.4	$	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.
Tampa Electric Company [Member]	'
Schedule of Regulatory Assets and Regulatory Liabilities	'
	Details of the regulatory assets and liabilities as of Dec. 31, 2013 and 2012 are presented in the following table:
	Regulatory Assets and Liabilities
	(millions)		Dec. 31,		Dec. 31,
			2013		2012
	Regulatory assets:
	Regulatory tax asset (1)		$	67.4	$	67.2
	Other:
	Cost-recovery clauses			6.1		42.9
	Postretirement benefit asset			182.7		276.1
	Deferred bond refinancing costs (2)			8		9.2
	Environmental remediation			51.4		46.9
	Competitive rate adjustment			4.1		4.1
	Other			7.7		6.5
	Total other regulatory assets			260		385.7
	Total regulatory assets			327.4		452.9
	Less: Current portion			34.3		70.3
	Long-term regulatory assets		$	293.1	$	382.6
	Regulatory liabilities:
	Regulatory tax liability (1)		$	9.8	$	14.6
	Other:
	Cost-recovery clauses			54.5		73.9
	Transmission and delivery storm reserve			56.1		50.4
	Deferred gain on property sales (3)			2		3.4
	Provision for stipulation and other			0.8		1
	Accumulated reserve - cost of removal			594		593.7
	Total other regulatory liabilities			707.4		722.4
	Total regulatory liabilities			717.2		737
	Less: Current portion			85.8		105.6
	Long-term regulatory liabilities		$	631.4	$	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.
Regulatory Assets and Related Recovery Period	'
	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)		Dec. 31,		Dec. 31,
			2013		2012
	Clause recoverable (1)		$	10.2	$	47
	Components of rate base (2)			185.6		279.1
	Regulatory tax assets (3)			67.4		67.2
	Capital structure and other (3)			64.2		59.6
	Total		$	327.4	$	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.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Income Tax Expense	'
	Income tax expense consists of the following:
	Income Tax Expense (Benefit)
	(millions)		2013			2012			2011
	For the year ended Dec. 31,
	Continuing Operations
	Current income taxes
	Federal		$	2.2		$	15.7		$	0
	State			(3.5	)		1.1			0.9
	Deferred income taxes
	Federal			98.6			102.9			124
	State			11.9			18.4			18.2
	Amortization of investment tax credits			(0.3	)		(0.3	)		(0.4	)
	Income tax expense from continuing operations		$	108.9		$	137.8		$	142.7
	Discontinued Operations
	Current income taxes
	Federal		$	0		$	0		$	0
	Foreign			0			6.8			7.4
	State			0			0			0
	Deferred income taxes
	Federal			(0.1	)		14.9			4.4
	Foreign			0			0			(0.3	)
	State			0			0.7			(0.3	)
	Income tax expense from discontinued operations			(0.1	)		22.4			11.2
	Total income tax expense		$	108.8		$	160.2		$	153.9
Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes	'
	The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:
	Effective Income Tax Rate
	(millions)		2013			2012			2011
	For the year ended Dec. 31,
	Income tax expense at the federal statutory rate of 35%		$	107.3		$	134.3		$	137.7
	Increase (decrease) due to:
	State income tax, net of federal income tax			5.5			12.7			12.4
	Equity portion of AFUDC			(2.2	)		(0.9	)		(0.4	)
	Valuation allowance			0			1.1			0
	Depletion			(3.7	)		(8.5	)		(9.1	)
	Other			2			(0.9	)		2.1
	Total income tax expense from continuing operations		$	108.9		$	137.8		$	142.7
	Income tax expense as a percent of income from continuing operations, before income taxes			35.5	%		35.9	%		36.3	%
Schedule of Deferred Tax Assets and Liabilities	'
	The major components of the company’s deferred tax assets and liabilities recognized are as follows:
	Deferred Income Taxes
	(millions)
	As of Dec. 31,		2013			2012
	Deferred tax liabilities (1)
	Property related		$	1,164.20		$	1,023.30
	Deferred fuel			1.6			11.3
	Pension			52.8			43
	Total deferred tax liabilities			1,218.60			1,077.60
	Deferred tax assets (1)
	Alternative minimum tax credit carryforward			213			211.8
	Loss and credit carryforwards (2)			479.8			473.2
	Other postretirement benefits			68.9			68
	Other			113.2			113
	Total deferred tax assets			874.9			866
	Valuation allowance			0			(3.0	)
	Total deferred tax assets, net of valuation allowance			874.9			863
	Total deferred tax liability, net			343.7			214.6
	Less: Current portion of deferred tax asset			(100.3	)		(63.3	)
	Long-term portion of deferred tax liability, net		$	444		$	277.9
	-1	Certain property related assets and liabilities have been netted.
	-2	As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2013 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.
Schedule of Unrecognized Tax Benefits	'
	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
	Unrecognized Tax Benefits
	(millions)		2013			2012
	Balance at Jan. 1,		$	2.9		$	4.1
	Decreases due to tax positions related to prior years			0			0
	Decreases due to settlements with taxing authorities			0			0
	Decreases due to expiration of statute of limitations			(2.9	)		0
	Dispositions			0			(1.2	)
	Balance at Dec. 31,		$	0		$	2.9
Tampa Electric Company [Member]	'
Schedule of Income Tax Expense	'
	Income tax expense consists of the following components:
	Income Tax Expense (Benefit)
	(millions)		2013			2012			2011
	For the year ending Dec. 31,
	Current income taxes
	Federal		$	19.4		$	(19.5	)	$	(30.7	)
	State			1.3			5.6			2.9
	Deferred income taxes
	Federal			99.8			141.2			155.6
	State			18.6			14.7			18
	Amortization of investment tax credits			(0.3	)		(0.3	)		(0.4	)
	Total income tax expense		$	138.8		$	141.7		$	145.4
Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes	'
	The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:
	Effective Income Tax Rate
	(millions)		2013			2012			2011
	For the years ended Dec. 31,
	Income tax expense at the federal statutory rate of 35%		$	127.5		$	129.1		$	133.2
	Increase (decrease) due to
	State income tax, net of federal income tax			13			13.2			13.6
	Equity portion of AFUDC			(2.2	)		(0.9	)		(0.4	)
	Domestic production deduction			(0.6	)		(0.4	)		(1.5	)
	Other			1.1			0.7			0.5
	Total income tax expense on consolidated statements of income		$	138.8		$	141.7		$	145.4
	Income tax expense as a percent of income from continuing operations, before income taxes			38.1	%		38.4	%		38.2	%
Schedule of Deferred Tax Assets and Liabilities	'
	The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:
	Deferred Income Taxes
	(millions)		2013			2012
	As of Dec. 31,
	Deferred tax liabilities (1)
	Property related		$	1,166.40		$	1,016.20
	Deferred fuel			1.6			11.3
	Pension and postretirement benefits			70.5			106.6
	Pension			43.2			36.7
	Other			0			22.2
	Total deferred tax liabilities			1,281.70			1,193.00
	Deferred tax assets (1)
	Medical benefits			50.9			49
	Insurance reserves			29.1			31.1
	Investment tax credits			5.3			5.5
	Hedging activities			4.9			5.5
	Pension and postretirement benefits			70.5			106.6
	Unbilled revenue			12.1			14.8
	Capitalized energy conservation assistance costs			19.6			19.6
	Other			4.4			0
	Total deferred tax assets			196.8			232.1
	Total deferred tax liability, net			1,084.90			960.9
	Less: Current portion of deferred tax asset			(29.4	)		(20.0	)
	Long-term portion of deferred tax liability, net		$	1,114.30		$	980.9
	-1	Certain property related assets and liabilities have been netted.

Employee_Postretirement_Benefi1

Employee Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Change in Benefit Obligation	'
	Obligations and Funded Status		Pension Benefits								Other Benefits
	(millions)		2013				2012				2013			2012
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	715			$	646.4			$	230.3		$	216.5
	Service cost			18.2				17				2.5			2.4
	Interest cost			28.9				30.1				9.3			10.1
	Plan participants’ contributions			0				0				2.9			3.7
	Plan amendments			0				0				0			(5.2	)
	Actuarial loss (gain)			(50.4	)			54.7				(22.1	)		16.3
	Gross benefits paid			(43.1	)			(33.2	)			(15.0	)		(14.5	)
	Settlements			(2.6	)			0				0			0
	Federal subsidy on benefits paid			n/a				n/a				0.2			1
	Net benefit obligation at end of year		$	666			$	715			$	208.1		$	230.3
Schedule of Change in Plan Assets	'
	Change in plan assets
	Fair value of plan assets at beginning of year		$	529.1			$	467.6			$	0		$	0
	Actual return on plan assets			63.7				57.9				0			0
	Employer contributions			45.9				36.8				11.9			9.8
	Plan participants’ contributions			0				0				2.9			3.7
	Settlements			(2.6	)			0				0			0
	Net benefits paid			(43.1	)			(33.2	)			(14.8	)		(13.5	)
	Fair value of plan assets at end of year		$	593			$	529.1			$	0		$	0
Schedule of Funded status	'
	Funded status
	Fair value of plan assets (1)		$	593			$	529.1			$	0		$	0
	Less: Benefit obligation (PBO/APBO)			666				715				208.1			230.3
	Funded status at end of year			(73.0	)			(185.9	)			(208.1	)		(230.3	)
	Unrecognized net actuarial loss			173.1				270.3				19.7			42.7
	Unrecognized prior service (benefit) cost			(0.4	)			(0.7	)			(0.7	)		(1.0	)
	Net amount required to be recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
	-1	The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.
Schedule of Amount Recognized in Balance Sheet	'
	Amounts recognized in balance sheet
	Regulatory assets		$	139.6			$	216.5			$	43.2		$	59.6
	Accrued benefit costs and other current liabilities			(3.3	)			(5.3	)			(13.3	)		(13.1	)
	Deferred credits and other liabilities			(69.7	)			(180.6	)			(194.8	)		(217.2	)
	Accumulated other comprehensive loss (income), pretax			33.1				53.1				(24.2	)		(17.9	)
	Net amount recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income	'
	Amounts recognized in accumulated other comprehensive income
			Pension Benefits								Other Benefits
	(millions)		2013				2012				2013			2012
	Net actuarial loss (gain)		$	32.7			$	52.7			$	(23.8	)	$	(17.2	)
	Prior service cost (credit)			0.4				0.4				(0.4	)		(0.7	)
	Amount recognized		$	33.1			$	53.1			$	(24.2	)	$	(17.9	)
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets	'
	The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
			Pension Benefits											Other Benefits
	Net periodic benefit cost
	(millions)		2013				2012				2011			2013			2012			2011
	Service cost		$	18.2			$	17			$	16		$	2.4		$	2.4		$	2.1
	Interest cost			28.9				30.1				30.9			9.3			10.1			11.1
	Expected return on plan assets			(38.4	)			(37.1	)			(38.4	)		0			0			0
	Amortization of:
	Actuarial loss			20.5				15.3				11.3			1			0.1			0.1
	Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)		(0.3	)		0.8			0.8
	Transition obligation			0				0				0			0			1.8			2.3
	Settlement loss			1				0				0.9			0			0			0
	Net periodic benefit cost		$	29.8			$	24.9			$	20.3		$	12.4		$	15.2		$	16.4
	Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and regulatory assets
	(millions)		2013				2012				2011			2013			2012			2011
	Prior service cost		$	0			$	0			$	0		$	0		$	(5.2	)	$	0
	Net loss (gain)			(75.7	)			34				43.3			(15.6	)		16.3			(7.4	)
	Amortization of:
	Actuarial gain (loss)			(21.5	)			(15.3	)		$	(12.2	)		(1.0	)		(0.1	)		(0.1	)
	Prior service (benefit) cost			0.4				0.4				0.4			0.3			(0.8	)		(0.8	)
	Transition obligation			0				0				0			0			(1.8	)		(2.4	)
	Total recognized in OCI and regulatory assets		$	(96.8	)		$	19.1			$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
	Total recognized in net periodic benefit cost, OCI and regulatory assets		$	(67.0	)		$	44			$	51.8		$	(3.9	)	$	23.6		$	5.7
Schedule of Pension Plan Assets	'
	The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.
			Target Allocation		Actual Allocation, End of Year
	Asset Category				2013				2012
	Equity securities		48%-54%			54	%			55	%
	Fixed income securities		46%-52%			46	%			45	%
	Total		100%			100	%			100	%
Schedule of Fair Value Hierarchy Plan's Investments	'
	The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and Dec. 31, 2012.
	Pension Plan Investments
	(millions)		At Fair Value as of Dec. 31, 2013
			Level 1				Level 2				Level 3			Total
	Accounts receivable		$	44.7			$	0			$	0		$	44.7
	Accounts payable			(40.8	)			0				0			(40.8	)
	Cash equivalents
	Short term investment funds (STIFs)			7.9				0				0			7.9
	Treasury bills (T bills)			0				0.3				0			0.3
	Repurchase agreement			0				8.8				0			8.8
	Commercial paper			0				0.4				0			0.4
	Money markets			0				1.5				0			1.5
	Total cash equivalents			7.9				11				0			18.9
	Equity securities
	Common stocks			91.6				0				0			91.6
	American depository receipts (ADRs)			3				0				0			3
	Real estate investment trusts (REITs)			1.7				0				0			1.7
	Preferred stock			0				0.8				0			0.8
	Mutual funds			172.6				0				0			172.6
	Commingled fund			0				50				0			50
	Total equity securities			268.9				50.8				0			319.7
	Fixed income securities
	Municipal bonds			0				7.3				0			7.3
	Government bonds			0				35.7				0			35.7
	Corporate bonds			0				19.6				0			19.6
	Asset backed securities (ABS)			0				0.4				0			0.4
	Mortgage-backed securities (MBS), net short sales			0				6.7				0			6.7
	Collateralized mortgage obligations (CMOs)			0				2.3				0			2.3
	Mutual fund			0				85.1				0			85.1
	Commingled fund			0				94.1				0			94.1
	Total fixed income securities			0				251.2				0			251.2
	Derivatives
	Short futures			0				0.2				0			0.2
	Swaps			0				(0.9	)			0			(0.9	)
	Purchased options (swaptions)			0				0.2				0			0.2
	Written options (swaptions)			0				(0.4	)			0			(0.4	)
	Total derivatives			0				(0.9	)			0			(0.9	)
	Miscellaneous			0				0.2				0			0.2
	Total		$	280.7			$	312.3			$	0		$	593
	Pension Plan Investments
	(millions)		At Fair Value as of Dec. 31, 2012
			Level 1				Level 2				Level 3			Total
	Accounts receivable		$	64.8			$	0			$	0		$	64.8
	Accounts payable			(72.8	)			0				0			(72.8	)
	Cash equivalents
	STIFs			9				0				0			9
	T bills			0				0.6				0			0.6
	Repurchase agreements			0				23.1				0			23.1
	CDs			0				1.1				0			1.1
	Commercial paper			0				0.9				0			0.9
	Money markets			0				0.6				0			0.6
	Total cash equivalents			9				26.3				0			35.3
	Equity securities
	Common stocks			125.3				0				0			125.3
	ADRs			6.2				0				0			6.2
	REITs			2				0				0			2
	Preferred stocks			0				0.8				0			0.8
	Equity mutual funds			153.4				0				0			153.4
	Total equity securities			286.9				0.8				0			287.7
	Fixed income securities
	Municipal bonds			0				8				0			8
	Government bonds			0				53				0			53
	Corporate bonds			0				19.8				0			19.8
ABS			0				0.5				0			0.5
MBS			0				17.6				0			17.6
CMBS			0				0.3				0			0.3
CMOs			0				2.5				0			2.5
Fixed income mutual fund			0				63.7				0			63.7
Fixed income commingled fund			0				49.4				0			49.4
Total fixed income securities			0				214.8				0			214.8
Derivatives
Swaps			0				(0.5	)			0			(0.5	)
Purchased options (swaptions)			0				0.1				0			0.1
Written options (swaptions)			0				(0.4	)			0			(0.4	)
Total derivatives			0				(0.8	)			0			(0.8	)
Miscellaneous			0				0.1				0			0.1
Total		$	287.9			$	241.2			$	0		$	529.1
	•		The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
	•		The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.
	•		The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.
	•		The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
	•		T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
	•		The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
	•		The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
	•		The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.
	•		The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
	•		The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
	•		Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.
	•		Swaps are valued using benchmark yields, swap curves, and cash flow analyses.
	•		Options are valued using the bid-ask spread and the last price.
Schedule of Benefit Payments	'
	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
	Expected Benefit Payments
	(including projected service and net of employee contributions)
	(millions)		Pension				Other
			Benefits				Postretirement
							Benefits
	2014		$	53.5			$	13.3
	2015			50.9				13.9
	2016			55.3				14.6
	2017			55.9				15.2
	2018			58.3				15.7
	2019-2023			298.6				81.9
Benefit Obligations [Member]	'
Schedule of Assumptions Used to Determine Benefit	'
	Assumptions used to determine benefit obligations at Dec. 31:
			Pension Benefits								Other Benefits
			2013				2012				2013			2012
	Discount rate			5.118	%			4.196	%			5.096	%		4.18	%
	Rate of compensation increase - weighted			3.73	%			3.76	%			3.71	%		3.74	%
	Healthcare cost trend rate
	Immediate rate			n/a				n/a				7.25	%		7.5	%
	Ultimate rate			n/a				n/a				4.5	%		4.5	%
	Year rate reaches ultimate			n/a				n/a				2025			2025
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	'
	A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:
	(millions)		1%				1%
			Increase				Decrease
	Effect on postretirement benefit obligation		$	6.8			$	(6.1	)
Net Periodic Benefit Cost [Member]	'
Schedule of Assumptions Used to Determine Benefit	'
	Assumptions used to determine net periodic benefit cost for years ended Dec. 31:
			Pension Benefits											Other Benefits
			2013				2012				2011			2013			2012			2011
	Discount rate			4.196	%			4.797	%			5.3	%		4.18	%		4.744	%		5.25	%
	Expected long-term return on plan assets			7.5	%			7.5	%			7.75	%		n/a			n/a			n/a
	Rate of compensation increase			3.76	%			3.83	%			3.88	%		3.74	%		3.82	%		3.87	%
	Healthcare cost trend rate
	Initial rate			n/a				n/a				n/a			7.5	%		7.75	%		8	%
	Ultimate rate			n/a				n/a				n/a			4.5	%		4.5	%		4.5	%
	Year rate reaches ultimate			n/a				n/a				n/a			2025			2025			2023
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	'
	A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:
	(millions)		1%				1%
			Increase				Decrease
	Effect on periodic cost		$	0.3			$	(0.3	)
Tampa Electric Company [Member]	'
Schedule of Amount Recognized in Balance Sheet	'
	Tampa Electric Company		Pension Benefits								Other Benefits
	Amounts recognized in balance sheet
	(millions)		2013				2012				2013			2012
	Regulatory assets		$	139.6			$	216.5			$	43.2		$	59.6
	Accrued benefit costs and other current liabilities			(0.9	)			(0.9	)			(10.8	)		(10.6	)
	Deferred credits and other liabilities			(50.1	)			(139.8	)			(158.3	)		(174.2	)
			$	88.6			$	75.8			$	(125.9	)	$	(125.2	)
Tampa Electric Company [Member] | Benefit Obligations [Member]	'
Schedule of Assumptions Used to Determine Benefit	'
	Assumptions used to determine benefit obligations at Dec. 31:
			Pension Benefits								Other Benefits
			2013				2012				2013			2012
	Discount rate			5.118	%			4.196	%			5.096	%		4.18	%
	Rate of compensation increase-weighted average			3.73	%			3.76	%			3.71	%		3.74	%
	Healthcare cost trend rate
	Immediate rate			n/a				n/a				7.25	%		7.5	%
	Ultimate rate			n/a				n/a				4.5	%		4.5	%
	Year rate reaches ultimate			n/a				n/a				2025			2025
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	'
	A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:
	(millions)		1% Increase				1% Decrease
	Effect on postretirement benefit obligation		$	5.6			$	(5.0	)
Tampa Electric Company [Member] | Net Periodic Benefit Cost [Member]	'
Schedule of Assumptions Used to Determine Benefit	'
	Assumptions used to determine net periodic benefit cost for years ended Dec. 31:
			Pension Benefits											Other Benefits
			2013				2012				2011			2013			2012			2011
	Discount rate			4.196	%			4.797	%			5.3	%		4.18	%		4.744	%		5.25	%
	Expected long-term return on plan assets			7.5	%			7.5	%			7.75	%		n/a			n/a			n/a
	Rate of compensation increase			3.76	%			3.83	%			3.88	%		3.74	%		3.82	%		3.87	%
	Healthcare cost trend rate
	Immediate rate			n/a				n/a				n/a			7.5	%		7.75	%		8	%
	Ultimate rate			n/a				n/a				n/a			4.5	%		4.5	%		4.5	%
	Year rate reaches ultimate			n/a				n/a				n/a			2025			2025			2023
Tampa Electric Company [Member] | Effect on Expenses [Member]	'
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	'
	A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:
	(millions)		1% Increase				1% Decrease
	Effect on periodic cost		$	0.2			$	(0.2	)
TECO Energy [Member]	'
Schedule of Change in Benefit Obligation	'
	TECO Energy		Pension Benefits								Other Benefits
	Obligations and Funded Status
	(millions)		2013				2012				2013			2012
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	715			$	646.4			$	230.3		$	216.5
	Service cost			18.2				17				2.5			2.4
	Interest cost			28.9				30.1				9.3			10.1
	Plan participants’ contributions			0				0				2.9			3.7
	Plan amendments			0				0				0			(5.2	)
	Actuarial loss (gain)			(50.4	)			54.7				(22.1	)		16.3
	Gross benefits paid			(43.1	)			(33.2	)			(15.0	)		(14.5	)
	Settlements			(2.6	)			0				0			0
	Federal subsidy on benefits paid			n/a				n/a				0.2			1
	Net benefit obligation at end of year		$	666			$	715			$	208.1		$	230.3
Schedule of Change in Plan Assets	'
	Change in plan assets
	Fair value of plan assets at beginning of year		$	529.1			$	467.6			$	0		$	0
	Actual return on plan assets			63.7				57.9				0			0
	Employer contributions			45.9				36.8				11.9			9.8
	Plan participants’ contributions			0				0				2.9			3.7
	Settlements			(2.6	)			0				0			0
	Gross benefits paid			(43.1	)			(33.2	)			(14.8	)		(13.5	)
	Fair value of plan assets at end of year		$	593			$	529.1			$	0		$	0
Schedule of Funded status	'
	Funded status
	Fair value of plan assets (1)		$	593			$	529.1			$	0		$	0
	Less: Benefit obligation (PBO/APBO)			666				715				208.1			230.3
	Funded status at end of year			(73.0	)			(185.9	)			(208.1	)		(230.3	)
	Unrecognized net actuarial loss			173.1				270.3				19.7			42.7
	Unrecognized prior service (benefit) cost			(0.4	)			(0.7	)			(0.7	)		(1.0	)
	Unrecognized net transition obligation			0				0				0			0
	Net amount required to be recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
	-1	The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.
Schedule of Amount Recognized in Balance Sheet	'
	Amounts recognized in balance sheet
	Regulatory assets		$	139.6			$	216.5			$	43.2		$	59.6
	Accrued benefit costs and other current liabilities			(3.3	)			(5.3	)			(13.3	)		(13.1	)
	Deferred credits and other liabilities			(69.7	)			(180.6	)			(194.8	)		(217.2	)
	Accumulated other comprehensive loss (income), pretax			33.1				53.1				(24.2	)		(17.9	)
	Net amount recognized at end of year		$	99.7			$	83.7			($	189.1	)	($	188.6	)
TECO Energy [Member]	'
Schedule of Pension Plan Assets	'
	TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.
			Target Allocation		Actual Allocation, End of Year
	Asset Category				2013				2012
	Equity securities		48%-54%			54	%			55	%
	Fixed income securities		46%-52%			46	%			45	%
	Total		100%			100	%			100	%
Schedule of Fair Value Hierarchy Plan's Investments	'
	The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and 2012.
	Pension Plan Investments
	(millions)		At Fair Value as of Dec. 31, 2013
			Level 1				Level 2				Level 3			Total
	Accounts receivable		$	44.7			$	0			$	0		$	44.7
	Accounts payable			(40.8	)			0				0			(40.8	)
	Cash equivalents
	STIFs			7.9				0				0			7.9
	T bills			0				0.3				0			0.3
	Repurchase agreements			0				8.8				0			8.8
	Commercial paper			0				0.4				0			0.4
	Money markets			0				1.5				0			1.5
	Total cash equivalents			7.9				11				0			18.9
	Equity securities
	Common stocks			91.6				0				0			91.6
	ADRs			3				0				0			3
	REITs			1.7				0				0			1.7
	Preferred stock			0				0.8				0			0.8
	Mutual funds			172.6				0				0			172.6
	Commingled fund			0				50				0			50
	Total equity securities			268.9				50.8				0			319.7
	Fixed income securities
	Municipal bonds			0				7.3				0			7.3
	Government bonds			0				35.7				0			35.7
	Corporate bonds			0				19.6				0			19.6
	ABS			0				0.4				0			0.4
	MBS, net short sales			0				6.7				0			6.7
	CMOs			0				2.3				0			2.3
	Mutual funds			0				85.1				0			85.1
	Commingled fund			0				94.1				0			94.1
	Total fixed income securities			0				251.2				0			251.2
	Derivatives
	Short futures			0				0.2				0			0.2
	Swaps			0				(0.9	)			0			(0.9	)
	Purchased options (swaptions)			0				0.2				0			0.2
	Written options (swaptions)			0				(0.4	)			0			(0.4	)
	Total derivatives			0				(0.9	)			0			(0.9	)
	Miscellaneous			0				0.2				0			0.2
	Total		$	280.7			$	312.3			$	0		$	593
	Pension Plan Investments
	(millions)		At Fair Value as of Dec. 31, 2012
			Level 1				Level 2				Level 3			Total
	Accounts receivable		$	64.8			$	0			$	0		$	64.8
	Accounts payable			(72.8	)			0				0			(72.8	)
	Cash equivalents
	STIFs			9				0				0			9
	T bills			0				0.6				0			0.6
	Repurchase agreements			0				23.1				0			23.1
	CDs			0				1.1				0			1.1
	Commercial paper			0				0.9				0			0.9
	Money markets			0				0.6				0			0.6
	Total cash equivalents			9				26.3				0			35.3
	Equity securities
	Common stocks			125.3				0				0			125.3
	ADRs			6.2				0				0			6.2
	REITs			2				0				0			2
	Preferred stocks			0				0.8				0			0.8
	Equity mutual funds			153.4				0				0			153.4
	Total equity securities			286.9				0.8				0			287.7
	Fixed income securities
	Municipal bonds			0				8				0			8
	Government bonds			0				53				0			53
	Corporate bonds			0				19.8				0			19.8
ABS			0				0.5				0			0.5
MBS			0				17.6				0			17.6
CMBS			0				0.3				0			0.3
CMOs			0				2.5				0			2.5
Fixed income mutual fund			0				63.7				0			63.7
Fixed income commingled fund			0				49.4				0			49.4
Total fixed income securities			0				214.8				0			214.8
Derivatives
Swaps			0				(0.5	)			0			(0.5	)
Purchased options (swaptions)			0				0.1				0			0.1
Written options (swaptions)			0				(0.4	)			0			(0.4	)
Total derivatives			0				(0.8	)			0			(0.8	)
Miscellaneous			0				0.1				0			0.1
Total		$	287.9			$	241.2			$	0		$	529.1
	•		The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
	•		The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.
	•		The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.
	•		The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
	•		T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
	•		The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
	•		The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
	•		The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.
	•		The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
	•		The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
	•		Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.
	•		Swaps are valued using benchmark yields, swap curves, and cash flow analyses.
	•		Options are valued using the bid-ask spread and the last price.
Schedule of Benefit Payments	'
	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
	Expected Benefit Payments - TECO Energy
	(including projected service and net of employee contributions)						Other
			Pension				Postretirement
	(millions)		Benefits				Benefits
	2014		$	53.5			$	13.3
	2015			50.9				13.9
	2016			55.3				14.6
	2017			55.9				15.2
	2018			58.3				15.7
	2019-2023			298.6				81.9
Schedule of Net Periodic Benefit Cost	'
	Components of TECO Energy Consolidated Net Periodic Benefit Cost
			Pension Benefits											Other Benefits
	(millions)		2013				2012				2011			2013			2012			2011
	Service cost		$	18.2			$	17			$	16		$	2.4		$	2.4		$	2.1
	Interest cost			28.9				30.1				30.9			9.3			10.1			11.1
	Expected return on plan assets			(38.4	)			(37.1	)			(38.4	)		0			0			0
	Amortization of:
	Actuarial loss			20.5				15.3				11.3			1			0.1			0.1
	Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)		(0.3	)		0.8			0.8
	Transition obligation			0				0				0			0			1.8			2.3
	Settlement loss			1				0				0.9			0			0			0
	Net periodic benefit cost		$	29.8			$	24.9			$	20.3		$	12.4		$	15.2		$	16.4
	Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets
	(millions)		2013				2012				2011			2013			2012			2011
	Prior service cost		$	0			$	0			$	0		$	0		$	(5.2	)	$	0
	Net loss (gain)			(75.7	)			34				43.3			(15.6	)		16.3			(7.4	)
	Amortization of:
	Actuarial gain (loss)			(21.5	)			(15.3	)			(12.2	)		(1.0	)		(0.1	)		(0.1	)
	Prior service (benefit) cost			0.4				0.4				0.4			0.3			(0.8	)		(0.8	)
	Transition obligation			0				0				0			0			(1.8	)		(2.4	)
	Total recognized in OCI and regulatory assets		$	(96.8	)		$	19.1			$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
	Total Recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets		$	(67.0	)		$	44			$	51.8		$	(3.9	)	$	23.6		$	5.7

ShortTerm_Debt_Tables

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Short-Term Debt Credit Facilities	'
	At Dec. 31, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:
	Credit Facilities
			Dec. 31, 2013						Dec. 31, 2012
	(millions)		Credit		Borrowings		Letters		Credit		Borrowings		Letters
			Facilities		Outstanding (1)		of Credit		Facilities		Outstanding (1)		of Credit
							Outstanding						Outstanding
	Tampa Electric Company:
	5-year facility (2)		$	325	$	6	$	0.7	$	325	$	0	$	1.5
	1-year accounts receivable facility			150		78		0		150		0		0
	TECO Energy/TECO Finance:
	5-year facility (2)(3)			200		0		0		200		0		0
	Total		$	675	$	84	$	0.7	$	675	$	0	$	1.5
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.
	-3	TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
Tampa Electric Company [Member]	'
Short-Term Debt Credit Facilities	'
	At Dec. 31, 2013 and 2012, the following credit facilities and related borrowings existed:
	Credit Facilities
			Dec. 31, 2013						Dec. 31, 2012
	(millions)		Credit		Borrowings		Letters		Credit		Borrowings		Letters
			Facilities		Outstanding (1)		of Credit		Facilities		Outstanding (1)		of Credit
							Outstanding						Outstanding
	Tampa Electric Company:
	5-year facility (2)		$	325	$	6	$	0.7	$	325	$	0	$	1.5
	1-year accounts receivable facility			150		78		0		150		0		0
	Total		$	475	$	84	$	0.7	$	475	$	0	$	1.5
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of Maturities of Long-Term Debt	'
	TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2014 through 2018 and thereafter are as follows:
	Long-Term Debt Maturities
	As of Dec. 31, 2013		2014			2015			2016			2017		2018		Thereafter		Total
	(millions)																	Long-Term
																		Debt
	TECO Finance		$	0		$	191.2		$	250		$	300	$	0	$	300	$	1,041.20
	Tampa Electric			83.3			83.3			83.4			0		254.2		1,146.70		1,650.90
	PGS			0			0			0			0		50		181.7		231.7
	Total long-term debt maturities		$	83.3		$	274.5		$	333.4		$	300	$	304.2	$	1,628.40	$	2,923.80
Schedule of Long-Term Debt Outstanding	'
	At Dec. 31, 2013 and 2012, TECO Energy had the following long-term debt outstanding:
	Long-Term Debt
	(millions) Dec. 31,				Due	2013			2012
	TECO Finance		Notes (1)(2)(3): 6.75% (effective rate of 6.9%)		2015	$	191.2		$	191.2
			4.0% (effective rate of 4.2%)		2016		250			250
			6.572% (effective rate of 7.3%)		2017		300			300
			5.15% (effective rate of 5.3%)		2020		300			300
	Total long-term debt of TECO Finance						1,041.20			1,041.20
	Tampa Electric		Installment contracts payable (4):
			5.65% Refunding bonds (effective rate of 5.9%)		2018		54.2			54.2
			Variable rate bonds repurchased in 2008 (5)		2020		0			0
			5.15% Refunding bonds repurchased in 2013 (effective rate of 5.4% for 2012) (6)		2025		0			51.6
			1.5% Term rate bonds repurchased in 2011 (7)		2030		0			0
			5.0% Refunding bonds repurchased in 2012 (8)		2034		0			0
			Notes (1): 6.25% (effective rate of 6.3%) (2)		2014-2016		250			250
			6.1% (effective rate of 6.0%)		2018		200			200
			5.4% (effective rate of 5.4%)		2021		231.7			231.7
			2.6% (effective rate of 2.7%)		2022		225			225
			6.55% (effective rate of 6.6%)		2036		250			250
			6.15% (effective rate of 6.2%)		2037		190			190
			4.1% (effective rate of 4.2%)		2042		250			250
	Total long-term debt of Tampa Electric						1,650.90			1,702.50
	PGS		Notes (1): 6.1% (effective rate of 7.0%)		2018		50			50
			5.4% (effective rate of 5.4%)		2021		46.7			46.7
			2.6% (effective rate of 2.7%)		2022		25			25
			6.15% (effective rate of 6.2%)		2037		60			60
			4.1% (effective rate of 4.2%)		2042		50			50
	Total long-term debt of PGS						231.7			231.7
	Total long-term debt of TECO Energy						2,923.80			2,975.40
	Unamortized debt discount, net						(2.7	)		(2.7	)
	Total carrying amount of long-term debt						2,921.10			2,972.70
	Less amount due within one year						83.3			0
	Total long-term debt					$	2,837.80		$	2,972.70
	-1	These securities are subject to redemption in whole or in part, at any time, at the option of the company.
	-2	These long-term debt agreements contain various restrictive financial covenants.
	-3	Guaranteed by TECO Energy.
	-4	Tax-exempt securities.
	-5	In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.
	-6	In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.
	-7	In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.
	-8	In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

Common_Stock_Tables

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Schedule of Assumptions Used to Determine Fair Value	'
	Assumptions		2013			2012			2011
	Assumptions applicable to performance-based restricted stock
	Risk-free interest rate			0.41	%		0.38	%		0.96	%
	Expected lives (in years)			3			3			3
	Expected stock volatility			19.04	%		20.99	%		34.61	%
	Dividend yield			4.83	%		4.78	%		4.48	%
Schedule of Additional Information on Compensation Costs and Income Tax Benefits and Excess Tax Benefits Related to Stock-Based Compensation Awards	'
	The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.
	(millions)		2013			2012			2011
	Compensation costs (1)		$	13.5		$	12		$	9.1
	Income tax benefits (1)			5.2			4.6			3.5
	Excess tax benefits (2)			0			2.6			1.7
	-1	Reflected on the Consolidated Statements of Income.
	-2	Reflected as financing activities on the Consolidated Statements of Cash Flows.
Summary of Non-Vested Shares of Restricted Stock	'
	A summary of non-vested shares of restricted stock is shown as follows:
	Nonvested Restricted Stock
			Time-Based Restricted						Performance-Based
			Stock (1)						Restricted Stock (1)
			Number of			Weighted -			Number of				Weighted-
			Shares			Avg. Grant			Shares				Avg. Grant
			(thousands)			Date			(thousands)				Date
						Fair Value							Fair Value
						(per share)							(per share)
	Nonvested balance at Dec. 31, 2012			592		$	18.04			1,490			$	17.13
	Granted			237			17.92			496				16.87
	Vested			(187	)		16.91			(434	)			17.2
	Forfeited			(4	)		17.99			(47	)			16.82
	Nonvested balance at Dec. 31, 2013			638		$	18.33			1,505			$	17.04
	-1	The weighted-average remaining contractual term of restricted stock is two years.
Summary of Stock Option Transactions	'
	Stock option transactions are summarized as follows:
	Stock Options
			Number of			Weighted-Avg.			Weighted-Avg.		Aggregate
			Shares			Option Price			Remaining		Intrinsic
			(thousands)			(per share)			Contractual		Value
									Term (years)		(millions)
	Outstanding balance at Dec. 31, 2012			2,087		$	15.05
	Granted			0			0
	Exercised			(507	)		13.22
	Cancelled			(13	)		18.87
	Outstanding balance at Dec. 31, 2013 (1)			1,567		$	15.62		2		$	2.6
	Exercisable at Dec. 31, 2013 (1)			1,567		$	15.62		2		$	2.6
	Available for future grant at Dec. 31, 2013			2,725
	-1	Option prices range from $12.01 to $19.01 per share.
Schedule of Option Outstanding and Exercisable	'
	As of Dec. 31, 2013, the options outstanding and exercisable are summarized below:
	Range of		Option Shares			Weighted-Avg.			Weighted-Avg.
	Option Prices		(thousands)			Option Price			Remaining
	(per share)					(per share)			Contractual Life
	$12.01 - $13.56			331		$	13.1		1 Years
	$16.21 - $19.01			1,236		$	16.29		2 Years
	Total			1,567		$	15.62		2 Years

Other_Comprehensive_Income_Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2013
Other Comprehensive Income	'
	TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:
	Other Comprehensive Income
	(millions)		Gross			Tax			Net
	2013
	Unrealized gain (loss) on cash flow hedges		$	1		$	(0.4	)	$	0.6
	Reclassification from AOCI to net income			1.3			(0.5	)		0.8
	Gain (Loss) on cash flow hedges			2.3			(0.9	)		1.4
	Amortization of unrecognized benefit costs and other			23.6			(8.8	)		14.8
	Recognized benefit costs due to settlement			2.6			(1.0	)		1.6
	Total other comprehensive income (loss)		$	28.5		$	(10.7	)	$	17.8
	2012
	Unrealized (loss) gain on cash flow hedges		$	(7.4	)	$	2.8		$	(4.6	)
	Reclassification from AOCI to net income			0.6			(0.2	)		0.4
	(Loss) Gain on cash flow hedges			(6.8	)		2.6			(4.2	)
	Amortization of unrecognized benefit costs and other (1)			(4.8	)		0			(4.8	)
	Total other comprehensive (loss) income		$	(11.6	)	$	2.6		$	(9.0	)
	2011
	Unrealized gain (loss) on cash flow hedges		$	1.8		$	(0.6	)	$	1.2
	Reclassification from AOCI to net income			(3.1	)		1.1			(2.0	)
	(Loss) Gain on cash flow hedges			(1.3	)		0.5			(0.8	)
	Amortization of unrecognized benefit costs and other			(7.9	)		3.3			(4.6	)
	Recognized benefit costs due to settlement			0.9			(0.3	)		0.6
	Total other comprehensive (loss) income		$	(8.3	)	$	3.5		$	(4.8	)
	-1	Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.
Accumulated Other Comprehensive Loss	'
	Accumulated Other Comprehensive Loss
	(millions) As of Dec. 31,		2013			2012
	Unrecognized pension losses and prior service credits (2)		$	(20.5	)	$	(32.9	)
	Unrecognized other benefit gains, prior service costs and transition obligations (3)			15.1			11.1
	Net unrealized losses from cash flow hedges (4)			(7.8	)		(9.2	)
	Total accumulated other comprehensive loss		$	(13.2	)	$	(31.0	)
	-2	Net of tax benefit of $12.6 million and $20.1 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.
	-3	Net of tax expense of $9.1 million and $6.7 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.
	-4	Net of tax benefit of $4.9 million and $5.8 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.
Tampa Electric Company [Member]	'
Other Comprehensive Income	'
	TEC reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:
	Other Comprehensive Income
	(millions)		Gross			Tax			Net
	2013
	Unrealized gain (loss) on cash flow hedges		$	0		$	0		$	0
	Reclassification from AOCI to net income			1.4			(0.5	)		0.9
	Gain (Loss) on cash flow hedges			1.4			(0.5	)		0.9
	Total other comprehensive income (loss)		$	1.4		($	0.5	)	$	0.9
	2012
	Unrealized (loss) gain on cash flow hedges		($	8	)	$	3.1		($	4.9	)
	Reclassification from AOCI to net income			1.4			(0.6	)		0.8
	(Loss) Gain on cash flow hedges			(6.6	)		2.5			(4.1	)
	Total other comprehensive (loss) income		($	6.6	)	$	2.5		($	4.1	)
	2011
	Unrealized gain (loss) on cash flow hedges		$	0		$	0		$	0
	Reclassification from AOCI to net income			1.2			(0.5	)		0.7
	Gain (Loss) on cash flow hedges			1.2			(0.5	)		0.7
	Total other comprehensive income (loss)		$	1.2		($	0.5	)	$	0.7
Accumulated Other Comprehensive Loss	'
	Accumulated Other Comprehensive Loss
	(millions) As of Dec. 31,		2013			2012
	Net unrealized losses from cash flow hedges (1)		($	7.8	)	($	8.7	)
	Total accumulated other comprehensive loss		($	7.8	)	($	8.7	)
	-1	Net of tax benefit of $4.9 million and $5.5 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share	'
	(millions, except per share amounts)		2013			2012			2011 (1)
	Basic earnings per share
	Net income from continuing operations		$	197.8		$	246		$	250.8
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.8	)		(1.3	)
	Income before discontinued operations available to common shareholders - Basic		$	197.2		$	245.2		$	249.5
	Income (loss) from discontinued operations attributable to TECO Energy, net		($	0.1	)	($	33.3	)	$	21.8
	Amount allocated to nonvested participating shareholders			0			0.1			(0.1	)
	Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic		($	0.1	)	($	33.2	)	$	21.7
	Net income attributable to TECO Energy		$	197.7		$	212.7		$	272.6
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.7	)		(1.4	)
	Net income attributable to TECO Energy available to common shareholders - Basic		$	197.1		$	212		$	271.2
	Average common shares outstanding - Basic			215			214.3			213.6
	Earnings per share from continuing operations available to common shareholders - Basic		$	0.92		$	1.14		$	1.17
	Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic		$	0		($	0.15	)	$	0.1
	Earnings per share attributable to TECO Energy available to common shareholders - Basic		$	0.92		$	0.99		$	1.27
	Diluted earnings per share
	Net income from continuing operations		$	197.8		$	246		$	250.8
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.8	)		(1.3	)
	Income before discontinued operations available to common shareholders - Diluted		$	197.2		$	245.2		$	249.5
	Income (loss) from discontinued operations attributable to TECO Energy, net		($	0.1	)	($	33.3	)	$	21.8
	Amount allocated to nonvested participating shareholders			0			0.1			(0.1	)
	Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted		($	0.1	)	($	33.2	)	$	21.7
	Net income attributable to TECO Energy		$	197.7		$	212.7		$	272.6
	Amount allocated to nonvested participating shareholders			(0.6	)		(0.7	)		(1.4	)
	Net income attributable to TECO Energy available to common shareholders - Diluted		$	197.1		$	212		$	271.2
	Unadjusted average common shares outstanding - Diluted			215			214.3			213.6
	Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net			0.5			0.7			1.5
	Average common shares outstanding - Diluted			215.5			215			215.1
	Earnings per share from continuing operations available to common shareholders - Diluted		$	0.92		$	1.14		$	1.17
	Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted		$	0		($	0.15	)	$	0.1
	Earnings per share attributable to TECO Energy available to common shareholders - Diluted		$	0.92		$	0.99		$	1.27
	Anti-dilutive shares			0			0.4			1.7
	-1	All prior periods presented reflect the classification of TECO Guatemala as discontinued operations (see Note 19).

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Future Minimum Lease Payments	'
	The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:
	Future Minimum Lease and Capacity Payments
	(millions)		Capacity		Operating		Total
			Payments		Leases
	Year ended Dec. 31:
	2014		$	14.8	$	5	$	19.8
	2015			14.9		3.9		18.8
	2016			14.6		2.6		17.2
	2017			9.9		2.4		12.3
	2018			10.1		2.2		12.3
	Thereafter			0		13.4		13.4
	Total future minimum payments		$	64.3	$	29.5	$	93.8
Letters of Credit and Guarantees	'
	A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2013 are as follows:
	Guarantees-TECO Energy
	(millions)						After (1)				Liabilities Recognized
	Guarantees for the Benefit of:		2014		2015-2018		2018		Total		at Dec. 31, 2013
	TECO Coal
	Fuel purchase related (2)		$	0.8	$	0.7	$	4	$	5.5	$	1.5
	Other subsidiaries
	Guaranty under sale agreement (3)			0		5		0		5		5
	Fuel sales and transportation (2)			10		0		91.8		101.8		0.1
	Total		$	10.8	$	5.7	$	95.8	$	112.3	$	6.6
	Letters of Credit-Tampa Electric Company
	(millions)						After (1)				Liabilities Recognized
	Letters of Credit for the Benefit of:		2014		2015-2018		2018		Total		at Dec. 31, 2013
	Tampa Electric (2)		$	0	$	0	$	0.7	$	0.7	$	0.1
	-1	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.
	-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 Dec. 31, 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. See Note 19 for additional information.
Tampa Electric Company [Member]	'
Schedule of Future Minimum Lease Payments	'
	The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:
	Future Minimum Lease and Capacity Payments
	(millions)		Capacity		Operating		Total
			Payments		Leases
	Year ended Dec. 31:
	2014		$	14.8	$	2.3	$	17.1
	2015			14.9		2.3		17.2
	2016			14.6		2.2		16.8
	2017			9.9		2.2		12.1
	2018			10.1		2.2		12.3
	Thereafter			0		13.4		13.4
	Total future minimum payments		$	64.3	$	24.6	$	88.9
Letters of Credit and Guarantees	'
	Letters of Credit - Tampa Electric Company
	(millions)		2014		2015-2018		After (1)		Total		Liabilities Recognized
	Letters of Credit for the Benefit of:						2018				at Dec. 31, 2013
	Tampa Electric (2)
	Letters of credit		$	0	$	0	$	0.7	$	0.7	$	0.1
	-1	These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2018.
	-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 Dec. 31, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Segment Information	'
	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 Financial Statements of TECO Energy, but are included in determining reportable segments.
	Segment Information
	(millions)		Tampa		PGS		TECO			TECO			Other &			TECO
			Electric				Coal			Guatemala			Eliminations			Energy
	2013
	Revenues - external		$	1,949.60	$	392.7	$	496.2		$	0		$	12.8		$	2,851.30
	Sales to affiliates			0.9		0.8		0			0			(1.7	)		0
	Total revenues			1,950.50		393.5		496.2			0			11.1			2,851.30
	Depreciation and amortization			238.8		51.5		37.7			0			1.5			329.5
	Total interest charges (1)			91.8		13.5		5.5			0			56.1			166.9
	Internally allocated interest (1)			0		0		6.4			0			(6.4	)		0
	Provision for income taxes			116.9		21.9		(3.6	)		0			(26.3	)		108.9
	Net income from continuing operations			190.9		34.7		9			0			(36.8	)		197.8
	Discontinued operations attributable to TECO, net of tax			0		0		0			0			(0.1	)		(0.1	)
	Net income attributable to TECO Energy			190.9		34.7		9			0			(36.9	)		197.7
	Total assets			6,126.90		1,021.20		316.3	(3)		0			(16.4	)		7,448.00
	Capital expenditures			428.6		79		22.4			0			2.4			532.4
	2012
	Revenues - external		$	1,980.70	$	396.6	$	608.9		$	0		$	10.4		$	2,996.60
	Sales to affiliates			0.6		2.3		0			0			(2.9	)		0
	Total revenues			1,981.30		398.9		608.9			0			7.5			2,996.60
	Depreciation and amortization			237.6		50.6		41			0			1.4			330.6
	Total interest charges (1)			109.8		16		7.1			0			50.6			183.5
	Internally allocated interest (1)			0		0		6.8			0			(6.8	)		0
	Provision for income taxes			120.2		21.5		15.7			0			(19.6	)		137.8
	Net income from continuing operations			193.1		34.1		50.2			0			(31.4	)		246
	Discontinued operations attributable to TECO, net of tax			0		0		0			(29.3	)		(4.0	)		(33.3	)
	Net income attributable to TECO Energy			193.1		34.1		50.2			(29.3	)		(35.4	)		212.7
	Total assets			6,042.30		1,009.90		356.6	(3)		164.9			(238.8	)		7,334.90
	Capital expenditures			361.7		97.3		36.3			8.6			1.2			505.1
	2011
	Revenues - external		$	2,019.30	$	450.5	$	733		$	0		$	7.1		$	3,209.90
	Sales to affiliates			1.3		3		0			0			(4.3	)		0
	Total revenues			2,020.60		453.5		733			0			2.8			3,209.90
	Depreciation and amortization			222.1		48.4		45.3			0			1.4			317.2
	Total interest charges (1)			121.8		17.7		6.9			0			51			197.4
	Internally allocated interest (1)			0		0		6.7			0			(6.7	)		0
	Provision for income taxes			124.8		20.6		15.4			0			(18.1	)		142.7
	Net income from continuing operations			202.7		32.6		51.5			0			(36.0	)		250.8
	Discontinued operations attributable to TECO, net of tax (2)			0		0		0			22.4			(0.6	)		21.8
	Net income attributable to TECO Energy			202.7		32.6		51.5			22.4			(36.6	)		272.6
	Goodwill			0		0		0			55.4			0			55.4
	Total assets			5,925.90		932		385.2	(3)		304.1			(240.0	)		7,307.20
	Capital expenditures			314.9		71.9		56.6			7.2			3.5			454.1
	-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 2013 and 2012 were at a pretax rate of 6.00%, and for 2011 were at a pretax rate of 6.25%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.
	-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. See Note 19.
	-3	The carrying value of mineral rights as of Dec. 31, 2013, 2012 and 2011 was $12.1 million, $13.4 million and $15.0 million, respectively.
Tampa Electric Company [Member]	'
Schedule of Segment Information	'
			Tampa				Other &
	(millions)		Electric		PGS		Eliminations			TEC
	2013
	Revenues - external		$	1,950.10	$	392.7	$	0		$	2,342.80
	Sales to affiliates			0.4		0.8		(1.2	)		0
	Total revenues			1,950.50		393.5		(1.2	)		2,342.80
	Depreciation and amortization			238.8		51.5		0			290.3
	Total interest charges			91.8		13.5		0			105.3
	Provision for income taxes			116.9		21.9		0			138.8
	Net income			190.9		34.7		0			225.6
	Total assets			5,895.40		989.3		(8.9	)		6,875.80
	Capital expenditures			428.6		79		0			507.6
	2012
	Revenues - external		$	1,980.90	$	397.1	$	0		$	2,378.00
	Sales to affiliates			0.4		1.8		(2.2	)		0
	Total revenues			1,981.30		398.9		(2.2	)		2,378.00
	Depreciation and amortization			237.6		50.6		0			288.2
	Total interest charges			109.8		16		0			125.8
	Provision for income taxes			120.2		21.5		0			141.7
	Net income			193.1		34.1		0			227.2
	Total assets			5,760.40		970.9		13.3			6,744.60
	Capital expenditures			361.7		97.3		0			459
	2011
	Revenues - external		$	2,020.10	$	450.5	$	0		$	2,470.60
	Sales to affiliates			0.5		3		(3.5	)		0
	Total revenues			2,020.60		453.5		(3.5	)		2,470.60
	Depreciation and amortization			222.1		48.4		0			270.5
	Total interest charges			121.8		17.7		0			139.5
	Provision for income taxes			124.8		20.6		0			145.4
	Net income			202.7		32.6		0			235.3
	Total assets			5,678.00		888.4		(10.0	)		6,556.40
	Capital expenditures			314.9		71.9		0			386.8

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Asset Retirement Obligations	'
	Reconciliation of beginning and ending carrying amount of asset retirement obligations:
			Dec. 31,
	(millions)		2013			2012
	Beginning balance		$	28.6		$	53.8
	Additional liabilities			0.1			0.7
	Liabilities settled			(1.4	)		(29.1	)
	Accretion expense			1.4			1.4
	Revisions to estimated cash flows			(0.3	)		0
	Other (1)			0.2			1.8
	Ending balance		$	28.6		$	28.6
	-1	Accretion recorded as a deferred regulatory asset.
Tampa Electric Company [Member]	'
Schedule of Asset Retirement Obligations	'
	Reconciliation of beginning and ending carrying amount of asset retirement obligations:
			Dec. 31,
	(millions)		2013			2012
	Beginning balance		$	5		$	30.8
	Additional liabilities			0.1			0
	Liabilities settled			(0.2	)		(27.6	)
	Revisions to estimated cash flows			(0.3	)		0
	Other (1)			0.2			1.8
	Ending balance		$	4.8		$	5
	-1	Accretion recorded as a deferred regulatory asset.

Accounting_for_Derivative_Inst1

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the derivatives that are designated as cash flow hedges at Dec. 31, 2013 and Dec. 31, 2012:
	Total Derivatives
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	9.7			$	0
	Long-term assets			0.3				0.2
	Total assets		$	10			$	0.2
	Current liabilities		$	0.1			$	14.6
	Long-term liabilities			0.2				0.6
	Total liabilities		$	0.3			$	15.2
Gross Amounts of Derivatives and Their Related Offset Amounts	'
	The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Dec. 31, 2013 and Dec. 31, 2012.
	Offsetting of Derivative Assets and Liabilities
	(millions)
			Gross Amounts				Gross				Net Amounts of
			of Recognized				Amounts Offset				Assets (Liabilities)
			Assets				on the Balance				Presented on the
			(Liabilities)				Sheet				Balance Sheet
	Dec. 31, 2013
	Description
	Derivative assets		$	10.5			$	(0.5	)		$	10
	Derivative liabilities		$	(0.8	)		$	0.5			$	(0.3	)
	Dec. 31, 2012
	Description
	Derivative assets		$	1			$	(0.8	)		$	0.2
	Derivative liabilities		$	(16.0	)		$	0.8			$	(15.2	)
Effect of Hedging Instruments on OCI and Income	'
	The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31:
			Amount of Gain/(Loss) on				Location of Gain/(Loss)		Gain/(Loss)
			Derivatives Recognized in				Reclassified From AOCI		Reclassified From
	(millions)		OCI				Into Income		AOCI Into Income
	Derivatives in Cash Flow Hedging Relationships			Effective Portion (1)			Effective Portion (1)
	2013
	Interest rate contracts:		$	0			Interest expense		($	0.9	)
	Commodity contracts:
	Diesel fuel derivatives			0.6			Mining related costs			0.1
	Total		$	0.6					($	0.8	)
	2012
	Interest rate contracts:		($	4.9	)		Interest expense		($	0.8	)
	Commodity contracts:
	Diesel fuel derivatives			0.3			Mining related costs			0.4
	Total		($	4.6	)				($	0.4	)
	2011
	Interest rate contracts:		$	0			Interest expense		($	0.7	)
	Commodity contracts:
	Diesel fuel derivatives			1.2			Mining related costs			2.7
	Total		$	1.2					$	2
	-1	Changes in OCI and AOCI are reported in after-tax dollars.
	(millions)		Fair Value				Amount of				Amount of
			Asset/(Liability)				Gain/(Loss)				Gain/(Loss)
							Recognized				Reclassified From
							in OCI (1)				AOCI Into Income (1)
	2013
	Interest rate swaps		$	0			$	0			($	0.9	)
	Diesel fuel derivatives			0.1				0.6				0.1
	Total		$	0.1			$	0.6			($	0.8	)
	2012
	Interest rate swaps		$	0			($	4.9	)		($	0.8	)
	Diesel fuel derivatives			(0.9	)			0.3				0.4
	Total		($	0.9	)		($	4.6	)		($	0.4	)
	2011
	Interest rate swaps		$	0			$	0			($	0.7	)
	Diesel fuel derivatives			(0.3	)			1.2				2.7
	Total		($	0.3	)		$	1.2			$	2
	-1	Changes in OCI and AOCI are reported in after-tax dollars.
Derivative Volumes Expected to Settle	'
	The following table presents by commodity type the company’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:
			Diesel Fuel Contracts								Natural Gas Contracts
	(millions)		(Gallons)								(MMBTUs)
	Year		Physical				Financial				Physical				Financial
	2014			0				2				0				36.9
	2015			0				0				0				7.6
	Total			0				2				0				44.5
Fair Value of Overall Contractual Contingent Liability Positions	'
	The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at Dec. 31, 2013:
	Contingent Features
	(millions)		Fair Value				Derivative				Posted
			Asset/				Exposure				Collateral
			(Liability)				Asset/
							(Liability)
	Credit Rating		($	0.1	)		($	0.1	)		$	0
Derivatives Designated as Hedging Instruments [Member]	'
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at Dec. 31, 2013 and 2012:
	Derivatives Designated As Hedging Instruments
			Asset Derivatives						Liability Derivatives
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2013		Location		Value				Location		Value
	Commodity Contracts:
	Diesel fuel derivatives:
	Current		Derivative assets		$	0.2			Derivative liabilities		$	0.1
	Long-term		Derivative assets			0			Derivative liabilities			0
	Natural gas derivatives:
	Current		Derivative assets			9.5			Derivative liabilities			0
	Long-term		Derivative assets			0.3			Derivative liabilities			0.2
	Total derivatives designated as hedging instruments				$	10					$	0.3
			Asset Derivatives						Liability Derivatives
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2012		Location		Value				Location		Value
	Commodity Contracts:
	Diesel fuel derivatives:
	Current		Derivative assets		$	0			Derivative liabilities		$	0.5
	Long-term		Derivative assets			0			Derivative liabilities			0.4
	Natural gas derivatives:
	Current		Derivative assets			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
Diesel Fuel Derivatives [Member]	'
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the derivative cash flow hedges of diesel fuel contracts at Dec. 31, 2013 and 2012 to limit the exposure to changes in the market price for diesel fuel:
	Diesel Fuel Derivatives
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	0.2			$	0
	Long-term assets			0				0
	Total assets		$	0.2			$	0
	Current liabilities		$	0.1			$	0.5
	Long-term liabilities			0				0.4
	Total liabilities		$	0.1			$	0.9
Natural Gas Derivatives [Member]	'
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the derivative hedges of natural gas contracts at Dec. 31, 2013 and 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 (1)
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	9.5			$	0
	Long-term assets			0.3				0.2
	Total assets		$	9.8			$	0.2
	Current liabilities		$	0			$	14.1
	Long-term liabilities			0.2				0.2
	Total liabilities		$	0.2			$	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.
Energy Related Derivatives [Member]	'
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism on the Consolidated Balance Sheets as of Dec. 31, 2013 and 2012:
	Energy Related Derivatives
			Asset Derivatives						Liability Derivatives
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2013		Location (1)		Value				Location (1)		Value
	Commodity Contracts:
	Natural gas derivatives:
	Current		Regulatory liabilities		$	9.5			Regulatory assets		$	0
	Long-term		Regulatory liabilities			0.3			Regulatory assets			0.2
	Total				$	9.8					$	0.2
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2012		Location (1)		Value				Location (1)		Value
	Commodity Contracts:
	Natural gas derivatives:
	Current		Regulatory liabilities		$	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 Statements of Income.
Tampa Electric Company [Member]	'
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism on the Consolidated Balance Sheets as of Dec. 31, 2013 and 2012:
	Energy Related Derivatives
			Asset Derivatives						Liability Derivatives
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2013		Location (1)		Value				Location (1)		Value
	Commodity Contracts:
	Natural gas derivatives:
	Current		Regulatory liabilities		$	9.5			Regulatory assets		$	0
	Long-term		Regulatory liabilities			0.3			Regulatory assets			0.2
	Total				$	9.8					$	0.2
	(millions)		Balance Sheet		Fair				Balance Sheet		Fair
	at Dec. 31, 2012		Location (1)		Value				Location (1)		Value
	Commodity Contracts:
	Natural gas derivatives:
	Current		Regulatory liabilities		$	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 Statements of Income.
Gross Amounts of Derivatives and Their Related Offset Amounts	'
	The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Dec. 31, 2013 and Dec. 31, 2012.
	Offsetting of Derivative Assets and Liabilities
	(millions)
			Gross Amounts				Gross				Net Amounts of
			of Recognized				Amounts Offset				Assets (Liabilities)
			Assets				on the Balance				Presented on the
			(Liabilities)				Sheet				Balance Sheet
	Dec. 31, 2013
	Description
	Derivative assets		$	10.3			$	(0.5	)		$	9.8
	Derivative liabilities		$	(0.7	)		$	0.5			$	(0.2	)
	Dec. 31, 2012
	Description
	Derivative assets		$	1			$	(0.8	)		$	0.2
	Derivative liabilities		$	(15.1	)		$	0.8			$	(14.3	)
Effect of Hedging Instruments on OCI and Income	'
	The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31, 2013, 2012 and 2011:
	(millions)		Location of Gain/(Loss) Reclassified		Amount of Gain/(Loss) Reclassified
			From AOCI Into Income		From AOCI Into Income
	For the years ended Dec. 31:				2013				2012				2011
	Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)
	Interest rate contracts:		Interest expense		($	0.9	)		($	0.8	)		($	0.7	)
	Total				($	0.9	)		($	0.8	)		($	0.7	)
	-1	Changes in OCI and AOCI are reported in after-tax dollars.
Derivative Volumes Expected to Settle	'
	The following table presents by commodity type TEC’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:
	(millions)		Natural Gas Contracts
			(MMBTUs)
	Year		Physical				Financial
	2014			0				36.9
	2015			0				7.6
	Total			0				44.5
Tampa Electric Company [Member] | Natural Gas Derivatives [Member]	'
Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet	'
	The following table presents the derivative cash flow hedges of natural gas contracts at Dec. 31, 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 (1)
	(millions)		Dec. 31,				Dec. 31,
			2013				2012
	Current assets		$	9.5			$	0
	Long-term assets			0.3				0.2
	Total assets		$	9.8			$	0.2
	Current liabilities		$	0			$	14.1
	Long-term liabilities			0.2				0.2
	Total liabilities		$	0.2			$	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.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Recurring Fair Value Measurements	'
	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 Dec. 31, 2013
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	9.8	$	0	$	9.8
	Diesel fuel swaps		0		0.2		0		0.2
	Total	$	0	$	10	$	0	$	10
	Liabilities
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Diesel fuel swaps		0		0.1		0		0.1
	Total	$	0	$	0.3	$	0	$	0.3
		At fair value as of Dec. 31, 2012
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Diesel fuel swaps		0		0		0		0
	Total	$	0	$	0.2	$	0	$	0.2
	Liabilities
	Natural gas swaps	$	0	$	14.3	$	0	$	14.3
	Diesel fuel swaps		0		0.9		0		0.9
	Total	$	0	$	15.2	$	0	$	15.2
Tampa Electric Company [Member]	'
Schedule of Recurring Fair Value Measurements	'
	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 Dec. 31, 2013
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	9.8	$	0	$	9.8
	Total	$	0	$	9.8	$	0	$	9.8
	Liabilities
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Total	$	0	$	0.2	$	0	$	0.2
		At fair value as of Dec. 31, 2012
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Total	$	0	$	0.2	$	0	$	0.2
	Liabilities
	Natural gas swaps	$	0	$	14.3	$	0	$	14.3
	Total	$	0	$	14.3	$	0	$	14.3

Discontinued_Operations_Tables

Discontinued Operations (Tables) (TECO Guatemala [Member])	12 Months Ended
	Dec. 31, 2013
TECO Guatemala [Member]	'
Components of Discontinued Operations	'
	The following table provides selected components of discontinued operations:
	Components of income from discontinued operations attributable to TECO Energy	Twelve months ended Dec. 31,
	(millions)	2013			2012			2011
	Revenues	$	0		$	114.2		$	133.5
	(Loss) income from operations		(0.2	)		27.7			33.7
	Loss on assets sold, including transaction costs		0			(38.3	)		(0.4	)
	Income (loss) from discontinued operations		(0.2	)		(10.6	)		33.3
	Provision (benefit) for income taxes		(0.1	)		22.4			11.2
	Income (loss) from discontinued operations, net		(0.1	)		(33.0	)		22.1
	Less: Income from discontinued operations attributable to noncontrolling interest		0			0.3			0.3
	Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8

Goodwill_and_Asset_Impairments1

Goodwill and Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Changes in Carrying Amount of Goodwill	'
	The changes in the carrying amount of goodwill for the year ended Dec. 31, 2012 are represented in the following table:
	(millions)	TPS GO			TPS SJI			Total
	Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4
	Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)
	Goodwill written off upon sale, pretax		0			(40.2	)		(40.2	)
	Balance as of Dec. 31, 2012	$	0		$	0		$	0

Quarterly_Data_unaudited_Table

Quarterly Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Financial Data by Quarter	'
	Financial data by quarter is as follows:
	(millions, except per share amounts)		Dec. 31		Sept. 30		June 30		March 31
	Quarter ended
	2013
	Revenues		$	688.4	$	765.9	$	735.9	$	661.1
	Income from operations			99.6		140.5		119.5		104.1
	Net income from continuing operations			42.1		62.9		51.6		41.2
	Net income attributable to TECO Energy			42		62.8		51.4		41.5
	EPS - Basic
	From continuing operations		$	0.2	$	0.29	$	0.24	$	0.19
	Attributable to TECO Energy			0.2		0.29		0.24		0.19
	EPS - Diluted
	From continuing operations		$	0.2	$	0.29	$	0.24	$	0.19
	Attributable to TECO Energy			0.2		0.29		0.24		0.19
	Dividends paid per common share outstanding		$	0.22	$	0.22	$	0.22	$	0.22
	Quarter ended		Dec. 31		Sept. 30		30-Jun		31-Mar
	2012
	Revenues (1)		$	688.4	$	858.6	$	752.5	$	697.1
	Income from operations (1)			109.5		183.1		149.1		114.8
	Net income from continuing operations (1)			45.6		90.2		65.6		44.6
	Net income attributable to TECO Energy			45.1		44		73.1		50.5
	EPS - Basic
	From continuing operations (1)		$	0.21	$	0.42	$	0.3	$	0.21
	Attributable to TECO Energy			0.21		0.2		0.34		0.24
	EPS - Diluted
	From continuing operations (1)		$	0.21	$	0.42	$	0.3	$	0.2
	Attributable to TECO Energy			0.21		0.2		0.34		0.23
	Dividends paid per common share outstanding		$	0.22	$	0.22	$	0.22	$	0.22
	-1	Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

Related_Parties_Tables

Related Parties (Tables) (Tampa Electric Company [Member])	12 Months Ended
	Dec. 31, 2013
Tampa Electric Company [Member]	'
Schedule of Related Parties	'
	A summary of activities between TEC and its affiliates follows:
	Net transactions with affiliates:
	(millions)		2013		2012		2011
	Natural gas sales, net		$	18.3	$	11.7	$	0
	Administrative and general, net		$	27.2	$	23.4	$	17.5
	Amounts due from or to affiliates at Dec. 31,
	(millions)		2013		2012
	Accounts receivable (1)		$	1.3	$	4.7
	Accounts payable (1)			9.8		7.9
	Taxes receivable			54.9		22.1
	Taxes payable			0.4		3.2
	-1	Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

Significant_Accounting_Policie3

Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended			56 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Equity method investment information	'In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest	'	'	'
Equity method investment, Ownership percentage	50.00%	'	'	50.00%
Restricted cash	$0	$8.70	'	0
Percentage of original cost of depreciable property	3.70%	3.80%	3.60%	'
Depreciation expense	316.5	309.3	306.6	'
Purchased power	64.7	105.3	125.9	'
Franchise fees and gross receipts taxes	108.5	111.5	109.3	'
Minimum [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Discount rates used in estimating other self-insurance liabilities	3.51%	2.60%	'	'
Minimum [Member] | Computer Software [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Amortization period	'2 years	'	'	'
Maximum [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Discount rates used in estimating other self-insurance liabilities	4.86%	4.00%	'	'
Maximum [Member] | Computer Software [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Amortization period	'15 years	'	'	'
Unbilled Revenues [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Unbilled revenues	46.7	49	'	46.7
Tampa Electric Company [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Equity method investment information	'In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest	'	'	'
Equity method investment, Ownership percentage	50.00%	'	'	50.00%
Percentage of original cost of depreciable property	3.70%	3.80%	3.60%	'
Depreciation expense	284.2	275.1	263.7	'
Allowance for funds used during construction rate	'	'	'	8.16%
Allowance for funds used during construction	9.9	4.1	1.6	'
Purchased power	64.7	105.3	125.9	'
Franchise fees and gross receipts taxes	108.5	111.5	109.3	'
Tampa Electric Company [Member] | Computer Software [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Amortization period	'15 years	'	'	'
Tampa Electric Company [Member] | Unbilled Revenues [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Unbilled revenues	46.7	49	'	46.7
TECO Energy Source [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Costs netted against revenues	23.1	13.8	2.5	'
TECO Coal [Member]	'	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Shipping and Handling	$8.20	$9	$16.60	'

Significant_Accounting_Policie4

Significant Accounting Policies - Estimated Useful Lives of Depreciable Property (Detail)	12 Months Ended
	Dec. 31, 2013
Minimum [Member] | Building and Improvements [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'5 years
Minimum [Member] | Office Equipment and Furniture [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'3 years
Minimum [Member] | Vehicles, Mining and Other Equipment [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'2 years
Minimum [Member] | Coal Processing Facilities [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'7 years
Minimum [Member] | Computer Software [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'2 years
Maximum [Member] | Building and Improvements [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'40 years
Maximum [Member] | Office Equipment and Furniture [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'30 years
Maximum [Member] | Vehicles, Mining and Other Equipment [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'15 years
Maximum [Member] | Coal Processing Facilities [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'20 years
Maximum [Member] | Computer Software [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Depreciable property estimated useful lives	'15 years

Significant_Accounting_Policie5

Significant Accounting Policies - Schedule of Fuel Inventory (Detail) (Fuel [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Inventory [Line Items]	'	'
Fuel inventory	$118.70	$123.60
Tampa Electric Company [Member]	'	'
Inventory [Line Items]	'	'
Fuel inventory	93.7	89.1
TECO Coal [Member]	'	'
Inventory [Line Items]	'	'
Fuel inventory	$25	$34.50

Regulatory_Additional_Informat

Regulatory - Additional Information (Detail) (Tampa Electric Company [Member], USD $)	0 Months Ended	12 Months Ended
	Feb. 04, 2013	Dec. 31, 2013	Apr. 05, 2013	Dec. 31, 2012
Percentage of return on equity	11.25%	11.25%	'	'
Allowed equity in the capital structure	'	54.00%	'	'
Period of average base rate	'	'13 months	'	'
Revenue due to average base rate	'	$3,400,000,000	'	'
Increase in revenue by modification in base rate	'	33,500,000	'	'
Additional Revenue generated from increase in service charge	'	'	134,800,000	'
Potential increase in ROE	'	10.25%	'	'
Return on equity range	'	'Range of plus or minus 1%	'	'
Amortization period for computer software under regulatory requirement description	'	'Tampa Electric will begin using a 15-year amortization period for all computer software	'	'
Annual accrual storm damage reserve	'	8,000,000	'	'
Storm damage reserve	'	56,100,000	'	50,400,000
Condition One [Member]	'	'	'	'
ROE lower range limit	'	11.25%	'	'
ROE upper range limit	'	9.25%	'	'
Condition Two [Member]	'	'	'	'
ROE lower range limit	'	11.50%	'	'
ROE upper range limit	'	9.50%	'	'
Transmission and Delivery Storm Reserve [Member]	'	'	'	'
Storm damage cost recovery period	'	'12 months	'	'
November 1, 2013 [Member]	'	'	'	'
Additional Revenue generated from increase in service charge	'	57,500,000	'	'
November 1, 2014 [Member]	'	'	'	'
Additional Revenue generated from increase in service charge	'	7,500,000	'	'
November 1, 2015 [Member]	'	'	'	'
Additional Revenue generated from increase in service charge	'	5,000,000	'	'
January 1,2017 [Member]	'	'	'	'
Additional Revenue generated from increase in service charge	'	110,000,000	'	'
Maximum [Member]	'	'	'	'
Higher Revenue Requirements	'	$104,000,000	'	'
Return on equity	12.25%	'	'	'
Potential increase in ROE	'	10.50%	'	'
Minimum [Member]	'	'	'	'
Return on equity	10.25%	'	'	'

Regulatory_Schedule_of_Regulat

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Regulatory assets:	'	'
Regulatory assets	$327.40	$452.90
Less: Current portion	34.3	70.3
Long-term regulatory assets	293.1	382.6
Regulatory liabilities:	'	'
Less: Current portion	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Tampa Electric Company [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	327.4	452.9
Less: Current portion	34.3	70.3
Long-term regulatory assets	293.1	382.6
Regulatory liabilities:	'	'
Regulatory liabilities	717.2	737
Less: Current portion	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Tampa Electric Company [Member] | Regulatory Tax Asset [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	9.8	14.6
Tampa Electric Company [Member] | Cost-Recovery Clauses [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	54.5	73.9
Tampa Electric Company [Member] | Transmission and Delivery Storm Reserve [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	56.1	50.4
Tampa Electric Company [Member] | Deferred Gain on Property Sales [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	2	3.4
Tampa Electric Company [Member] | Provision for Stipulation and Other [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	0.8	1
Tampa Electric Company [Member] | Accumulated Reserve - Cost of Removal [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	594	593.7
Tampa Electric Company [Member] | Total Other Regulatory Liabilities [Member]	'	'
Regulatory liabilities:	'	'
Regulatory liabilities	707.4	722.4
Tampa Electric Company [Member] | Regulatory Tax Asset [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	67.4	67.2
Tampa Electric Company [Member] | Cost-Recovery Clauses [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	6.1	42.9
Tampa Electric Company [Member] | Postretirement Benefit Costs [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	182.7	276.1
Tampa Electric Company [Member] | Deferred Bond Refinancing Costs [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	8	9.2
Tampa Electric Company [Member] | Environmental Remediation [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	51.4	46.9
Tampa Electric Company [Member] | Competitive Rate Adjustment [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	4.1	4.1
Tampa Electric Company [Member] | Other [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	7.7	6.5
Tampa Electric Company [Member] | Total Other Regulatory Assets [Member]	'	'
Regulatory assets:	'	'
Regulatory assets	$260	$385.70

Regulatory_Schedule_of_Regulat1

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]	'	'
Amortization period	'5-year	'5-year
Tampa Electric Company [Member]	'	'
Regulatory Assets [Line Items]	'	'
Amortization period	'5-year	'5-year

Regulatory_Regulatory_Assets_a

Regulatory - Regulatory Assets and Related Recovery Periods (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Regulatory Assets [Line Items]	'	'
Regulatory assets	$327.40	$452.90
Tampa Electric Company [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	327.4	452.9
Clause Recoverable [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	10.2	47
Clause Recoverable [Member] | Tampa Electric Company [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	10.2	47
Components of Rate Base [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	185.6	279.1
Components of Rate Base [Member] | Tampa Electric Company [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	185.6	279.1
Regulatory Tax Asset [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	67.4	67.2
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	67.4	67.2
Capital Structure and Other [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	64.2	59.6
Capital Structure and Other [Member] | Tampa Electric Company [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	$64.20	$59.60

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'
Income Tax Expense Benefit	$108.80	$160.20	$153.90
Cash paid for income taxes	1.8	7.2	9.4
Use of operating loss carryforward	'	13.6	32.1
Effective tax rate	35.00%	35.00%	35.00%
Federal and state (Florida) net operating losses (NOL's) carry forward	1,321.90	'	'
Deferred tax assets expiration date	'2025 and 2028	'	'
General business credit	3.9	'	'
Deferred tax general business credits expiration date	'2026 and 2032	'	'
Foreign tax credits	38.5	'	'
Tax credit carry forwards	213	211.8	'
Valuation allowance release	3	'	'
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%	'	'
Interest charges associated with uncertain tax positions	-0.9	0.3	0.2
Interest accrued	0	0.9	'
Penalties	0	'	'
Income tax examination period	'1 year	'	'
State and Local Jurisdiction [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Federal and state (Florida) net operating losses (NOL's) carry forward	392.6	'	'
Capital loss carryforward valuation allowance	'	3	'
Minimum [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Effective tax rate	35.00%	'	'
Tax credit carry forwards	211.8	'	'
Statutes of limitations	'3 years	'	'
Maximum [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Tax credit carry forwards	213	'	'
Statutes of limitations	'4 years	'	'
Tampa Electric Company [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Cash paid for income taxes	$56.40	($9.70)	($31.10)
Effective tax rate	35.00%	35.00%	35.00%
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%	'	'
Statutes of limitations	'3 years	'	'
Income tax examination period	'1 year	'	'

Income_Taxes_Schedule_of_Incom

Income Taxes - Schedule of Income Tax Expense (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred income taxes	'	'	'
Total income tax expense	$108.80	$160.20	$153.90
Deferred income taxes	'	'	'
Amortization of investment tax credits	-0.3	-0.3	-0.4
Income tax expense from continuing operations	108.9	137.8	142.7
Continuing Operations [Member]	'	'	'
Current income taxes	'	'	'
Current income taxes, Federal	2.2	15.7	0
Current income taxes, State	-3.5	1.1	0.9
Deferred income taxes	'	'	'
Deferred income taxes, Federal	98.6	102.9	124
Deferred income taxes, State	11.9	18.4	18.2
Current income taxes	'	'	'
Current income taxes, Federal	2.2	15.7	0
Current income taxes, State	-3.5	1.1	0.9
Deferred income taxes	'	'	'
Deferred income taxes, Federal	98.6	102.9	124
Deferred income taxes, State	11.9	18.4	18.2
Amortization of investment tax credits	-0.3	-0.3	-0.4
Income tax expense from continuing operations	108.9	137.8	142.7
Discontinued Operations [Member]	'	'	'
Current income taxes	'	'	'
Current income taxes, Federal	0	0	0
Current income taxes, State	0	0	0
Deferred income taxes	'	'	'
Deferred income taxes, Federal	-0.1	14.9	4.4
Deferred income taxes, State	0	0.7	-0.3
Income tax expense from discontinued operations	-0.1	22.4	11.2
Current income taxes	'	'	'
Current income taxes, Federal	0	0	0
Current income taxes, Foreign	0	6.8	7.4
Current income taxes, State	0	0	0
Deferred income taxes	'	'	'
Deferred income taxes, Federal	-0.1	14.9	4.4
Deferred income taxes, State	0	0.7	-0.3
Current income taxes, Foreign	0	0	-0.3
Tampa Electric Company [Member]	'	'	'
Current income taxes	'	'	'
Current income taxes, Federal	19.4	-19.5	-30.7
Current income taxes, State	1.3	5.6	2.9
Deferred income taxes	'	'	'
Deferred income taxes, Federal	99.8	141.2	155.6
Deferred income taxes, State	18.6	14.7	18
Current income taxes	'	'	'
Current income taxes, Federal	19.4	-19.5	-30.7
Current income taxes, State	1.3	5.6	2.9
Deferred income taxes	'	'	'
Deferred income taxes, Federal	99.8	141.2	155.6
Deferred income taxes, State	18.6	14.7	18
Amortization of investment tax credits	-0.3	-0.3	-0.4
Income tax expense from continuing operations	$138.80	$141.70	$145.40

Income_Taxes_Schedule_of_Incom1

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]	'	'	'
Income tax expense at the federal statutory rate of 35%	$107.30	$134.30	$137.70
State income tax, net of federal income tax	5.5	12.7	12.4
Equity portion of AFUDC	-2.2	-0.9	-0.4
Valuation allowance	0	1.1	0
Depletion	-3.7	-8.5	-9.1
Other	2	-0.9	2.1
Income tax expense from continuing operations	108.9	137.8	142.7
Income tax expense as a percent of income from continuing operations, before income taxes	35.50%	35.90%	36.30%
Tampa Electric Company [Member]	'	'	'
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]	'	'	'
Income tax expense at the federal statutory rate of 35%	127.5	129.1	133.2
State income tax, net of federal income tax	13	13.2	13.6
Equity portion of AFUDC	-2.2	-0.9	-0.4
Domestic production deduction	-0.6	-0.4	-1.5
Other	1.1	0.7	0.5
Income tax expense from continuing operations	$138.80	$141.70	$145.40
Income tax expense as a percent of income from continuing operations, before income taxes	38.10%	38.40%	38.20%

Income_Taxes_Schedule_of_Incom2

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]	'	'	'
Statutory tax rate	35.00%	35.00%	35.00%
Tampa Electric Company [Member]	'	'	'
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]	'	'	'
Statutory tax rate	35.00%	35.00%	35.00%

Income_Taxes_Schedule_of_Defer

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Deferred tax liabilities	'	'
Property related	$1,164.20	$1,023.30
Deferred fuel	1.6	11.3
Pension	52.8	43
Total deferred tax liabilities	1,218.60	1,077.60
Deferred tax assets	'	'
Alternative minimum tax credit carryforward	213	211.8
Loss and credit carryforwards	479.8	473.2
Other postretirement benefits	68.9	68
Other	113.2	113
Total deferred tax assets	874.9	866
Valuation allowance	0	-3
Total deferred tax assets, net of valuation allowance	874.9	863
Total deferred tax liability, net	343.7	214.6
Less: Current portion of deferred tax asset	-100.3	-63.3
Long-term portion of deferred tax liability, net	444	277.9
Tampa Electric Company [Member]	'	'
Deferred tax liabilities	'	'
Property related	1,166.40	1,016.20
Deferred fuel	1.6	11.3
Pension	43.2	36.7
Total deferred tax liabilities	1,281.70	1,193
Pension and postretirement benefits	70.5	106.6
Other	0	22.2
Deferred tax assets	'	'
Other	4.4	0
Total deferred tax assets	196.8	232.1
Medical benefits	50.9	49
Insurance reserves	29.1	31.1
Investment tax credits	5.3	5.5
Hedging activities	4.9	5.5
Pension and postretirement benefits	70.5	106.6
Unbilled revenue	12.1	14.8
Capitalized energy conservation assistance costs	19.6	19.6
Total deferred tax liability, net	1,084.90	960.9
Less: Current portion of deferred tax asset	-29.4	-20
Long-term portion of deferred tax liability, net	$1,114.30	$980.90

Income_Taxes_Schedule_of_Defer1

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Stockholder's equity increment	$1.10

Income_Taxes_Schedule_of_Unrec

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Beginning Balance	$2.90	$4.10
Decreases due to tax positions related to prior years	0	0
Decreases due to settlements with taxing authorities	0	0
Decreases due to expiration of statute of limitations	-2.9	0
Dispositions	0	-1.2
Ending Balance	$0	$2.90

Employee_Postretirement_Benefi2

Employee Postretirement Benefits - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Primary provisions for pension benefits	'First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%.	'	'
Percentage of qualified pension plan's actuarial value of assets	'	96.70%	'
Estimated percentage of qualified pension plan's actuarial value of assets	98.20%	'	'
Percentage of tax-free subsidy under prescription drug programs	28.00%	'	'
Amortization period of Regulatory Asset	'12 years	'	'
Tax of premiums paid for retiree medical benefits plan	40.00%	'	'
Accumulated benefit obligation of defined benefit pension plans	$624.10	$664.70	'
Percentage of defined benefit plan actual return on plan assets	12.00%	'	'
Employer contributions	42	35.5	'
Employer contributions in next fiscal year	47.5	'	'
Defined contribution plan, maximum employer match percentage	6.00%	'	'
Description of defined contribution plan	'Employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%.	'	'
Defined contribution plan cost recognized	11.3	7	9
Employer matching contribution percentage of eligible participant contribution	60.00%	'	'
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	40.00%	'	'
Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Percentage of qualified pension plan's actuarial value of assets	'	96.70%	'
Estimated percentage of qualified pension plan's actuarial value of assets	98.20%	'	'
Percentage of tax-free subsidy under prescription drug programs	28.00%	'	'
Tax of premiums paid for retiree medical benefits plan	40.00%	'	'
Employer contributions	33.5	27.9	'
Employer contributions in next fiscal year	38.4	'	'
Defined contribution plan cost recognized	9.1	6	5.8
TECO Energy [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Percentage of defined benefit plan actual return on plan assets	12.00%	'	'
TECO Coal [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Black lung liability	24.5	27.1	'
Expenses related to black lung liability	2.2	1.8	1.7
Pre Amendment [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer matching contribution percentage of eligible participant contribution	60.00%	'	'
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	40.00%	'	'
Post Amendment [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer matching contribution percentage of eligible participant contribution	65.00%	'	'
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	35.00%	'	'
Minimum [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Range of estimated annual contributions	4	'	'
Minimum [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Range of estimated annual contributions	3	'	'
Maximum [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Range of estimated annual contributions	48	'	'
Maximum [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Range of estimated annual contributions	39	'	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Projected benefit obligation for other postretirement benefits	666	715	646.4
Estimated net loss amortization from AOCI into net periodic benefit cost related to defined benefit plan	2.5	'	'
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.1	'	'
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	10.5	'	'
Defined benefit plan prior service benefit that will be amortized from regulatory assets in next fiscal year	0.5	'	'
Employer contributions	45.9	36.8	'
Net periodic benefit cost	29.8	24.9	20.3
Pension Benefits [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	10.5	'	'
Defined benefit plan prior service benefit that will be amortized from regulatory assets in next fiscal year	0.5	'	'
Net periodic benefit cost	21.7	18.3	13.1
Pension Benefits [Member] | TECO Energy [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Projected benefit obligation for other postretirement benefits	666	715	646.4
Employer contributions	45.9	36.8	'
Net periodic benefit cost	29.8	24.9	20.3
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Projected benefit obligation for other postretirement benefits	208.1	230.3	216.5
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.2	'	'
Other postretirement benefit plans, Net loss that will be amortized from regulatory assets in next fiscal year	0	'	'
Employer contributions	11.9	9.8	'
Employer contributions in next fiscal year	13.3	'	'
Net periodic benefit cost	12.4	15.2	16.4
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Other postretirement benefit plans, Net loss that will be amortized from regulatory assets in next fiscal year	0	'	'
Employer contributions in next fiscal year	10.8	'	'
Net periodic benefit cost	10	12.4	10
Other Postretirement Benefits [Member] | TECO Energy [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Projected benefit obligation for other postretirement benefits	208.1	230.3	216.5
Employer contributions	11.9	9.8	'
Net periodic benefit cost	12.4	15.2	16.4
SERP [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	2.6	1.3	'
Employer contributions in next fiscal year	3.3	'	'
SERP [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	1	0.6	'
Employer contributions in next fiscal year	$0.90	'	'

Employee_Postretirement_Benefi3

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Net benefit obligation at beginning of year	$715	$646.40	'
Service cost	18.2	17	16
Interest cost	28.9	30.1	30.9
Plan participants' contributions	0	0	'
Plan amendments	0	0	'
Actuarial loss (gain)	-50.4	54.7	'
Gross benefits paid	-43.1	-33.2	'
Settlements	-2.6	0	'
Federal subsidy on benefits paid	'	'	'
Net benefit obligation at end of year	666	715	646.4
Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Net benefit obligation at beginning of year	230.3	216.5	'
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Plan participants' contributions	2.9	3.7	'
Plan amendments	0	-5.2	'
Actuarial loss (gain)	-22.1	16.3	'
Gross benefits paid	-15	-14.5	'
Settlements	0	0	'
Federal subsidy on benefits paid	0.2	1	'
Net benefit obligation at end of year	208.1	230.3	216.5
TECO Energy [Member] | Pension Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Net benefit obligation at beginning of year	715	646.4	'
Service cost	18.2	17	16
Interest cost	28.9	30.1	30.9
Plan participants' contributions	0	0	'
Plan amendments	0	0	'
Actuarial loss (gain)	-50.4	54.7	'
Gross benefits paid	-43.1	-33.2	'
Settlements	-2.6	0	'
Net benefit obligation at end of year	666	715	646.4
TECO Energy [Member] | Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Net benefit obligation at beginning of year	230.3	216.5	'
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Plan participants' contributions	2.9	3.7	'
Plan amendments	0	-5.2	'
Actuarial loss (gain)	-22.1	16.3	'
Gross benefits paid	-15	-14.5	'
Settlements	0	0	'
Federal subsidy on benefits paid	0.2	1	'
Net benefit obligation at end of year	$208.10	$230.30	$216.50

Employee_Postretirement_Benefi4

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Change in plan assets	'	'
Fair value of plan assets at beginning of year	$529,100,000	'
Employer contributions	42,000,000	35,500,000
Fair value of plan assets at end of year	593,000,000	529,100,000
Pension Benefits [Member]	'	'
Change in plan assets	'	'
Fair value of plan assets at beginning of year	529,100,000	467,600,000
Actual return on plan assets	63,700,000	57,900,000
Employer contributions	45,900,000	36,800,000
Plan participants' contributions	0	0
Settlements	-2,600,000	0
Gross benefits paid	-43,100,000	-33,200,000
Fair value of plan assets at end of year	593,000,000	529,100,000
Other Postretirement Benefits [Member]	'	'
Change in plan assets	'	'
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	11,900,000	9,800,000
Plan participants' contributions	2,900,000	3,700,000
Settlements	0	0
Gross benefits paid	-14,800,000	-13,500,000
Fair value of plan assets at end of year	0	0
TECO Energy [Member] | Pension Benefits [Member]	'	'
Change in plan assets	'	'
Fair value of plan assets at beginning of year	529,100,000	467,600,000
Actual return on plan assets	63,700,000	57,900,000
Employer contributions	45,900,000	36,800,000
Plan participants' contributions	0	0
Settlements	-2,600,000	0
Gross benefits paid	-43,100,000	-33,200,000
Fair value of plan assets at end of year	593,000,000	529,100,000
TECO Energy [Member] | Other Postretirement Benefits [Member]	'	'
Change in plan assets	'	'
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	11,900,000	9,800,000
Plan participants' contributions	2,900,000	3,700,000
Settlements	0	0
Gross benefits paid	-14,800,000	-13,500,000
Fair value of plan assets at end of year	$0	$0

Employee_Postretirement_Benefi5

Employee Postretirement Benefits - Schedule of Funded Status (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	$593,000,000	$529,100,000	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	593,000,000	529,100,000	467,600,000
Less: Benefit obligation (PBO/APBO)	666,000,000	715,000,000	646,400,000
Funded status at end of year	-73,000,000	-185,900,000	'
Unrecognized net actuarial loss	173,100,000	270,300,000	'
Unrecognized prior service (benefit) cost	-400,000	-700,000	'
Net amount required to be recognized at end of year	99,700,000	83,700,000	'
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	0
Less: Benefit obligation (PBO/APBO)	208,100,000	230,300,000	216,500,000
Funded status at end of year	-208,100,000	-230,300,000	'
Unrecognized net actuarial loss	19,700,000	42,700,000	'
Unrecognized prior service (benefit) cost	-700,000	-1,000,000	'
Net amount required to be recognized at end of year	-189,100,000	-188,600,000	'
TECO Energy [Member] | Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	593,000,000	529,100,000	467,600,000
Less: Benefit obligation (PBO/APBO)	666,000,000	715,000,000	646,400,000
Funded status at end of year	-73,000,000	-185,900,000	'
Unrecognized net actuarial loss	173,100,000	270,300,000	'
Unrecognized prior service (benefit) cost	-400,000	-700,000	'
Net amount required to be recognized at end of year	99,700,000	83,700,000	'
Unrecognized net transition obligation	0	0	'
TECO Energy [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	0
Less: Benefit obligation (PBO/APBO)	208,100,000	230,300,000	216,500,000
Funded status at end of year	-208,100,000	-230,300,000	'
Unrecognized net actuarial loss	19,700,000	42,700,000	'
Unrecognized prior service (benefit) cost	-700,000	-1,000,000	'
Net amount required to be recognized at end of year	-189,100,000	-188,600,000	'
Unrecognized net transition obligation	$0	$0	'

Employee_Postretirement_Benefi6

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	$139.60	$216.50
Accrued benefit costs and other current liabilities	-3.3	-5.3
Deferred credits and other liabilities	-69.7	-180.6
Accumulated other comprehensive loss (income), pretax	33.1	53.1
Net amount recognized at end of year	99.7	83.7
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	-13.3	-13.1
Deferred credits and other liabilities	-194.8	-217.2
Accumulated other comprehensive loss (income), pretax	-24.2	-17.9
Net amount recognized at end of year	-189.1	-188.6
TECO Energy [Member] | Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	139.6	216.5
Accrued benefit costs and other current liabilities	-3.3	-5.3
Deferred credits and other liabilities	-69.7	-180.6
Accumulated other comprehensive loss (income), pretax	33.1	53.1
Net amount recognized at end of year	99.7	83.7
TECO Energy [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	-13.3	-13.1
Deferred credits and other liabilities	-194.8	-217.2
Accumulated other comprehensive loss (income), pretax	-24.2	-17.9
Net amount recognized at end of year	($189.10)	($188.60)

Employee_Postretirement_Benefi7

Employee Postretirement Benefits - Schedule of Funded Status (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	'5 years	'5 years
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	'5 years	'5 years
TECO Energy [Member] | Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	'5 years	'5 years
TECO Energy [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	'5 years	'5 years

Employee_Postretirement_Benefi8

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Net actuarial loss (gain)	$32.70	$52.70
Prior service cost (credit)	0.4	0.4
Amount recognized	33.1	53.1
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Net actuarial loss (gain)	-23.8	-17.2
Prior service cost (credit)	-0.4	-0.7
Amount recognized	($24.20)	($17.90)

Employee_Postretirement_Benefi9

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	5.12%	4.20%	'
Rate of compensation increase - weighted	3.73%	3.76%	'
Healthcare cost trend rate	'	'	'
Immediate rate	'	'	'
Ultimate rate	'	'	'
Year rate reaches ultimate	'	'	'
Pension Benefits [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	5.12%	4.20%	'
Rate of compensation increase - weighted	3.73%	3.76%	'
Healthcare cost trend rate	'	'	'
Immediate rate	'	'	'
Ultimate rate	'	'	'
Year rate reaches ultimate	'	'	'
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	5.10%	4.18%	'
Rate of compensation increase - weighted	3.71%	3.74%	'
Healthcare cost trend rate	'	'	'
Immediate rate	7.25%	7.50%	'
Ultimate rate	4.50%	4.50%	'
Year rate reaches ultimate	'2025	'2025	'
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	5.10%	4.18%	'
Rate of compensation increase - weighted	3.71%	3.74%	'
Healthcare cost trend rate	'	'	'
Immediate rate	7.25%	7.50%	'
Ultimate rate	4.50%	4.50%	'
Year rate reaches ultimate	'2025	'2025	'
Net Periodic Benefit Cost [Member] | Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	4.20%	4.80%	5.30%
Expected long-term return on plan assets	7.50%	7.50%	7.75%
Rate of compensation increase	3.76%	3.83%	3.88%
Healthcare cost trend rate	'	'	'
Immediate rate	'	'	'
Ultimate rate	'	'	'
Year rate reaches ultimate	'	'	'
Net Periodic Benefit Cost [Member] | Pension Benefits [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	4.20%	4.80%	5.30%
Expected long-term return on plan assets	7.50%	7.50%	7.75%
Rate of compensation increase	3.76%	3.83%	3.88%
Healthcare cost trend rate	'	'	'
Immediate rate	'	'	'
Ultimate rate	'	'	'
Year rate reaches ultimate	'	'	'
Net Periodic Benefit Cost [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	4.18%	4.74%	5.25%
Expected long-term return on plan assets	'	'	'
Rate of compensation increase	3.74%	3.82%	3.87%
Healthcare cost trend rate	'	'	'
Immediate rate	7.50%	7.75%	8.00%
Ultimate rate	4.50%	4.50%	4.50%
Year rate reaches ultimate	'2025	'2025	'2023
Net Periodic Benefit Cost [Member] | Other Postretirement Benefits [Member] | Tampa Electric Company [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	4.18%	4.74%	5.25%
Rate of compensation increase	3.74%	3.82%	3.87%
Healthcare cost trend rate	'	'	'
Immediate rate	7.50%	7.75%	8.00%
Ultimate rate	4.50%	4.50%	4.50%
Year rate reaches ultimate	'2025	'2025	'2023

Recovered_Sheet1

Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]	'
Effect on periodic cost - Increase	$0.30
Effect on periodic cost - Decrease	-0.3
Tampa Electric Company [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Effect on periodic cost - Increase	0.2
Effect on periodic cost - Decrease	-0.2
Assumed One-percentage-point Change [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Effect on postretirement benefit obligation - Increase	6.8
Effect on postretirement benefit obligation - Decrease	-6.1
Assumed One-percentage-point Change [Member] | Tampa Electric Company [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Effect on postretirement benefit obligation - Increase	5.6
Effect on postretirement benefit obligation - Decrease	($5)

Recovered_Sheet2

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	$18.20	$17	$16
Interest cost	28.9	30.1	30.9
Expected return on plan assets	-38.4	-37.1	-38.4
Amortization of:	'	'	'
Actuarial loss	20.5	15.3	11.3
Prior service (benefit) cost	-0.4	-0.4	-0.4
Transition obligation	0	0	0
Settlement loss	1	0	0.9
Net periodic benefit cost	29.8	24.9	20.3
Prior service cost	0	0	0
Net loss (gain)	-75.7	34	43.3
Amortization of:	'	'	'
Actuarial gain (loss)	-21.5	-15.3	-12.2
Prior service (benefit) cost	0.4	0.4	0.4
Transition obligation	0	0	0
Total recognized in OCI and regulatory assets	-96.8	19.1	31.5
Total recognized in net periodic benefit cost, OCI and regulatory assets	-67	44	51.8
Pension Benefits [Member] | TECO Energy [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	18.2	17	16
Interest cost	28.9	30.1	30.9
Expected return on plan assets	-38.4	-37.1	-38.4
Amortization of:	'	'	'
Actuarial loss	20.5	15.3	11.3
Prior service (benefit) cost	-0.4	-0.4	-0.4
Transition obligation	0	0	0
Settlement loss	1	0	0.9
Net periodic benefit cost	29.8	24.9	20.3
Prior service cost	0	0	0
Net loss (gain)	-75.7	34	43.3
Amortization of:	'	'	'
Actuarial gain (loss)	-21.5	-15.3	-12.2
Prior service (benefit) cost	0.4	0.4	0.4
Transition obligation	0	0	0
Total recognized in OCI and regulatory assets	-96.8	19.1	31.5
Total recognized in net periodic benefit cost, OCI and regulatory assets	-67	44	51.8
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Expected return on plan assets	0	0	0
Amortization of:	'	'	'
Actuarial loss	1	0.1	0.1
Prior service (benefit) cost	-0.3	0.8	0.8
Transition obligation	0	1.8	2.3
Settlement loss	0	0	0
Net periodic benefit cost	12.4	15.2	16.4
Prior service cost	0	-5.2	0
Net loss (gain)	-15.6	16.3	-7.4
Amortization of:	'	'	'
Actuarial gain (loss)	-1	-0.1	-0.1
Prior service (benefit) cost	0.3	-0.8	-0.8
Transition obligation	0	-1.8	-2.4
Total recognized in OCI and regulatory assets	-16.3	8.4	-10.7
Total recognized in net periodic benefit cost, OCI and regulatory assets	-3.9	23.6	5.7
Other Postretirement Benefits [Member] | TECO Energy [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Expected return on plan assets	0	0	0
Amortization of:	'	'	'
Actuarial loss	1	0.1	0.1
Prior service (benefit) cost	-0.3	0.8	0.8
Transition obligation	0	1.8	2.3
Settlement loss	0	0	0
Net periodic benefit cost	12.4	15.2	16.4
Prior service cost	0	-5.2	0
Net loss (gain)	-15.6	16.3	-7.4
Amortization of:	'	'	'
Actuarial gain (loss)	-1	-0.1	-0.1
Prior service (benefit) cost	0.3	-0.8	-0.8
Transition obligation	0	-1.8	-2.4
Total recognized in OCI and regulatory assets	-16.3	8.4	-10.7
Total recognized in net periodic benefit cost, OCI and regulatory assets	($3.90)	$23.60	$5.70

Recovered_Sheet3

Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Actual Asset Allocation [Member]

Actual Asset Allocation [Member]

Actual Asset Allocation [Member]

Actual Asset Allocation [Member]

Actual Asset Allocation [Member]

Actual Asset Allocation [Member]

Target Allocation [Member]

Target Allocation [Member]

Target Allocation [Member]

Target Allocation [Member]

Target Allocation [Member]

Equity Securities [Member]

Equity Securities [Member]

Fixed Income Securities [Member]

Fixed Income Securities [Member]

Equity Securities [Member]

Equity Securities [Member]

Fixed Income Securities [Member]

Fixed Income Securities [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Asset Category

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity securities

'

'

'

'

'

'

'

'

100.00%

48.00%

54.00%

46.00%

52.00%

Actual Allocation, End of Year

'

'

100.00%

100.00%

54.00%

55.00%

46.00%

45.00%

'

'

'

'

'

Total

$593,000,000

$529,100,000

$1

$1

'

'

'

'

'

'

'

'

'

Target Allocation

'

'

'

'

'

'

'

'

100.00%

48.00%

54.00%

46.00%

52.00%

Asset Category

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity securities

'

'

'

'

'

'

'

'

100.00%

48.00%

54.00%

46.00%

52.00%

Actual Allocation, End of Year

'

'

100.00%

100.00%

54.00%

55.00%

46.00%

45.00%

'

'

'

'

'

Total

$593,000,000

$529,100,000

$1

$1

'

'

'

'

'

'

'

'

'

Target Allocation

'

'

'

'

'

'

'

'

100.00%

48.00%

54.00%

46.00%

52.00%

Recovered_Sheet4

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	$593,000,000	$529,100,000
Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	214,800,000
Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	44,700,000	64,800,000
Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-40,800,000	-72,800,000
Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	18,900,000	35,300,000
Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,900,000	9,000,000
Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	300,000	600,000
Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	8,800,000	23,100,000
Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	900,000
Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,500,000	600,000
Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	1,100,000
Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	319,700,000	287,700,000
Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	91,600,000	125,300,000
Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	3,000,000	6,200,000
Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,700,000	2,000,000
Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	800,000	800,000
Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	172,600,000	153,400,000
Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	50,000,000	'
Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	251,200,000	63,700,000
Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	94,100,000	'
Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,300,000	8,000,000
Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	35,700,000	53,000,000
Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	19,600,000	19,800,000
Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	500,000
Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	6,700,000	17,600,000
Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	2,300,000	2,500,000
Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	85,100,000	'
Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	300,000
Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-800,000
Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	'
Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-500,000
Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-400,000	-400,000
Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	49,400,000
Level 1 [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	280,700,000	287,900,000
Level 1 [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 1 [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	44,700,000	64,800,000
Level 1 [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-40,800,000	-72,800,000
Level 1 [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,900,000	9,000,000
Level 1 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,900,000	9,000,000
Level 1 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 1 [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	268,900,000	286,900,000
Level 1 [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	91,600,000	125,300,000
Level 1 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	3,000,000	6,200,000
Level 1 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,700,000	2,000,000
Level 1 [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	172,600,000	153,400,000
Level 1 [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 1 [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 1 [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 1 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 1 [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 1 [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 1 [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 2 [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	312,300,000	241,200,000
Level 2 [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	214,800,000
Level 2 [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	11,000,000	26,300,000
Level 2 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	300,000	600,000
Level 2 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	8,800,000	23,100,000
Level 2 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	900,000
Level 2 [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,500,000	600,000
Level 2 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	1,100,000
Level 2 [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	50,800,000	800,000
Level 2 [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	800,000	800,000
Level 2 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	50,000,000	'
Level 2 [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	251,200,000	63,700,000
Level 2 [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	94,100,000	'
Level 2 [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,300,000	8,000,000
Level 2 [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	35,700,000	53,000,000
Level 2 [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	19,600,000	19,800,000
Level 2 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	500,000
Level 2 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	6,700,000	17,600,000
Level 2 [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	2,300,000	2,500,000
Level 2 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	85,100,000	'
Level 2 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	300,000
Level 2 [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-800,000
Level 2 [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	'
Level 2 [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-500,000
Level 2 [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Level 2 [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-400,000	-400,000
Level 2 [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Level 2 [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	49,400,000
Level 3 [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 3 [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 3 [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 3 [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 3 [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 3 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Level 3 [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Level 3 [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Level 3 [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Tampa Electric Company [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	593,000,000	529,100,000
Tampa Electric Company [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	44,700,000	64,800,000
Tampa Electric Company [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-40,800,000	-72,800,000
Tampa Electric Company [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	18,900,000	35,300,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,900,000	9,000,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	300,000	600,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	8,800,000	23,100,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	900,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,500,000	600,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	1,100,000
Tampa Electric Company [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	319,700,000	287,700,000
Tampa Electric Company [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	91,600,000	125,300,000
Tampa Electric Company [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	3,000,000	6,200,000
Tampa Electric Company [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,700,000	2,000,000
Tampa Electric Company [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	800,000	800,000
Tampa Electric Company [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	172,600,000	153,400,000
Tampa Electric Company [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	50,000,000	'
Tampa Electric Company [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	251,200,000	214,800,000
Tampa Electric Company [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	94,100,000	49,400,000
Tampa Electric Company [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,300,000	8,000,000
Tampa Electric Company [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	35,700,000	53,000,000
Tampa Electric Company [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	19,600,000	19,800,000
Tampa Electric Company [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	500,000
Tampa Electric Company [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	6,700,000	17,600,000
Tampa Electric Company [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	2,300,000	2,500,000
Tampa Electric Company [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	85,100,000	63,700,000
Tampa Electric Company [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	300,000
Tampa Electric Company [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-800,000
Tampa Electric Company [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	'
Tampa Electric Company [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-500,000
Tampa Electric Company [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-400,000	-400,000
Tampa Electric Company [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Level 1 [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	280,700,000	287,900,000
Tampa Electric Company [Member] | Level 1 [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	44,700,000	64,800,000
Tampa Electric Company [Member] | Level 1 [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-40,800,000	-72,800,000
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,900,000	9,000,000
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,900,000	9,000,000
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	268,900,000	286,900,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	91,600,000	125,300,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	3,000,000	6,200,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,700,000	2,000,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	172,600,000	153,400,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	312,300,000	241,200,000
Tampa Electric Company [Member] | Level 2 [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	11,000,000	26,300,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	300,000	600,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	8,800,000	23,100,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	900,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	1,500,000	600,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	1,100,000
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	50,800,000	800,000
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	800,000	800,000
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	50,000,000	'
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	251,200,000	214,800,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	94,100,000	49,400,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	7,300,000	8,000,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	35,700,000	53,000,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	19,600,000	19,800,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	400,000	500,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	6,700,000	17,600,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	2,300,000	2,500,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	85,100,000	63,700,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	300,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-800,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	'
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-900,000	-500,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	-400,000	-400,000
Tampa Electric Company [Member] | Level 2 [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Level 3 [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Accounts Receivable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Accounts Payable [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Money Markets [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Common Stock [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Preferred Stocks [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Commingled Fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Municipal Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Government Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Corporate Bonds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | CMO [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	'	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Short Term Funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	'
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Swaps [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Purchased Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Written Options [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Miscellaneous [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets	$0	$0

Recovered_Sheet5

Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Expected Benefit Payments - 2014	$53.50
Expected Benefit Payments - 2015	50.9
Expected Benefit Payments - 2016	55.3
Expected Benefit Payments - 2017	55.9
Expected Benefit Payments - 2018	58.3
Expected Benefit Payments - 2019-2023	298.6
Pension Benefits [Member] | TECO Energy [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Expected Benefit Payments - 2014	53.5
Expected Benefit Payments - 2015	50.9
Expected Benefit Payments - 2016	55.3
Expected Benefit Payments - 2017	55.9
Expected Benefit Payments - 2018	58.3
Expected Benefit Payments - 2019-2023	298.6
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Expected Benefit Payments - 2014	13.3
Expected Benefit Payments - 2015	13.9
Expected Benefit Payments - 2016	14.6
Expected Benefit Payments - 2017	15.2
Expected Benefit Payments - 2018	15.7
Expected Benefit Payments - 2019-2023	81.9
Other Postretirement Benefits [Member] | TECO Energy [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Expected Benefit Payments - 2014	13.3
Expected Benefit Payments - 2015	13.9
Expected Benefit Payments - 2016	14.6
Expected Benefit Payments - 2017	15.2
Expected Benefit Payments - 2018	15.7
Expected Benefit Payments - 2019-2023	$81.90

ShortTerm_Debt_Credit_Faciliti

Short-Term Debt - Credit Facilities (Detail) (USD $)	Dec. 31, 2013	Dec. 17, 2013	Dec. 31, 2012
Line of Credit Facility [Line Items]	'	'	'
Credit Facilities	$675,000,000	'	$675,000,000
Borrowings Outstanding	84,000,000	'	0
Letters of Credit Outstanding	700,000	'	1,500,000
Tampa Electric Company [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Credit Facilities	475,000,000	200,000,000	475,000,000
Borrowings Outstanding	84,000,000	'	0
Letters of Credit Outstanding	700,000	'	1,500,000
Tampa Electric Company [Member] | 5-year Facility [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Credit Facilities	325,000,000	'	325,000,000
Borrowings Outstanding	6,000,000	'	0
Letters of Credit Outstanding	700,000	'	1,500,000
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Credit Facilities	150,000,000	'	150,000,000
Borrowings Outstanding	78,000,000	'	0
Letters of Credit Outstanding	0	'	0
TECO Energy [Member] | 5-year Facility [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Credit Facilities	200,000,000	'	200,000,000
Borrowings Outstanding	0	'	0
Letters of Credit Outstanding	$0	'	$0

ShortTerm_Debt_Credit_Faciliti1

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013
Line of Credit Facility [Line Items]	'
Credit facility maturity date	17-Dec-18
Tampa Electric Company [Member]	'
Line of Credit Facility [Line Items]	'
Credit facility maturity date	17-Dec-18

ShortTerm_Debt_Additional_Info

Short-Term Debt - Additional Information (Detail) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 17, 2013

Feb. 15, 2014

Feb. 15, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 17, 2013

Dec. 17, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 17, 2013

Dec. 17, 2013

Feb. 15, 2014

Feb. 15, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Revolving Credit Facility [Member]

Subsequent Event [Member]

Subsequent Event [Member]

TECO Energy [Member]

TECO Energy [Member]

TECO Finance [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

1-year Accounts Receivable Facility [Member]

Revolving Credit Facility [Member]

1-year Accounts Receivable Facility [Member]

1-year Accounts Receivable Facility [Member]

Amended And Restated Credit Agreement [Member]

Amended And Restated Credit Agreement [Member]

Previous Agreement [Member]

Subsequent Event [Member]

Subsequent Event [Member]

TECO Energy [Member]

Tampa Electric Company [Member]

TECO Energy [Member]

TECO Energy [Member]

Tampa Electric Company [Member]

1-year Accounts Receivable Facility [Member]

Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment fees, percentage

'

'

'

'

0.70%

'

'

'

'

'

'

'

'

'

'

'

0.70%

'

0.13%

'

0.13%

0.25%

'

'

0.25%

Outstanding borrowings

$84,000,000

$0

'

'

'

'

'

'

'

$84,000,000

$0

$78,000,000

$0

'

'

'

'

'

'

'

'

'

'

'

'

Weighted-average interest rate

0.56%

'

'

'

'

'

'

'

'

0.56%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amended credit facility

675,000,000

675,000,000

200,000,000

'

150,000,000

'

'

200,000,000

200,000,000

475,000,000

475,000,000

150,000,000

150,000,000

'

325,000,000

200,000,000

150,000,000

150,000,000

'

'

'

'

'

'

'

Debt instrument maturity date

'

'

'

'Feb. 13, 2015

'Feb. 13, 2015

'

'

'

'

'

'

'

'

'Oct. 25, 2016 to Dec. 17, 2018

'

'

'Feb. 13, 2015

'

'

'

'

'

'

'

'

Amended maturity date of credit facility

17-Dec-18

'

'

'

'

'

'

'

'

17-Dec-18

'

'

'

'

'

'

'

'

'

25-Oct-16

'

'

17-Dec-18

'

'

Interest rate description

'

'

'

'

'

'TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%.

'

'

'Tampa Electric Company to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase of credit facility

'

'

'

'

'

'

'

$100,000,000

$175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Normal capitalization ratio

'

'

'

'

'

'

0.65

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.7

'

Long_Term_Debt_Additional_Info

Long Term Debt - Additional Information (Detail) (USD $)

2 Months Ended

12 Months Ended

2 Months Ended

9 Months Ended

12 Months Ended

12 Months Ended

11 Months Ended

9 Months Ended

5 Months Ended

3 Months Ended

9 Months Ended

48 Months Ended

65 Months Ended

12 Months Ended

3 Months Ended

8 Months Ended

48 Months Ended

65 Months Ended

0 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

3 Months Ended

Mar. 01, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 01, 2011

Sep. 28, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 02, 2012

Dec. 19, 2012

Dec. 05, 2012

Sep. 28, 2012

Jun. 05, 2012

Mar. 15, 2012

Mar. 26, 2008

Sep. 03, 2013

Mar. 15, 2012

Sep. 01, 2013

Dec. 31, 2013

Mar. 15, 2012

Mar. 26, 2008

Sep. 03, 2013

Mar. 15, 2012

Sep. 01, 2013

Oct. 02, 2012

Oct. 02, 2012

Oct. 02, 2012

Dec. 31, 2013

Oct. 02, 2012

Oct. 02, 2012

Mar. 01, 2011

Mar. 01, 2011

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

San Jose [Member]

6.75% Notes due 2015 [Member]

2.6% Notes [Member]

4.1% Notes [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

HCIDA Pollution Control Revenue Refunding Bonds [Member]

PCIDA Bonds [Member]

PCIDA Bonds [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Held Bonds [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Five Point One Percentage Refunding Bonds [Member]

Five Point Five Percentage Refunding Bonds [Member]

Tampa Electric Company [Member]

2013 [Member]

2013 [Member]

2023 [Member]

Held Bonds [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

2013 [Member]

2023 [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt, carrying amount

'

$2,921,100,000

$2,972,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated fair value

'

3,184,100,000

3,442,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership of parent company

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase in lieu of redemption

75,000,000

51,600,000

650,400,000

153,600,000

75,000,000

'

51,600,000

608,000,000

78,800,000

'

25,300,000

'

'

'

86,000,000

20,000,000

51,600,000

'

'

232,600,000

86,000,000

20,000,000

51,600,000

'

'

'

'

'

232,600,000

60,700,000

86,400,000

'

'

Interest at the initial term rate per annum

'

'

'

'

'

'

'

'

'

'

'

'

2.60%

4.10%

'

'

'

5.00%

5.15%

'

'

'

'

5.00%

5.15%

'

5.10%

5.50%

'

'

'

1.50%

1.50%

Principal amounts of notes redeemed

'

'

'

'

'

'

'

'

'

147,100,000

'

8,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price of notes

'

'

'

'

'

'

'

'

'

'

'

1,141,860,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount issued

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

250,000,000

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on debt extinguishment

'

0

-1,200,000

0

'

'

'

'

'

'

'

1,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redeemable principal amount percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

Issuance of notes, maturity year

'

'

'

'

'

'

'

'

'

'

'

'

1-Jan-22

1-Jan-42

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument Principal amount Market Price Percentage

'

'

'

'

'

'

'

'

'

'

'

'

99.88%

99.72%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from notes net of issuance

'

'

'

'

'

'

'

'

'

'

'

'

$247,700,000

$296,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Libor interest rate

'

'

'

'

'

'15

'

'

'

'

'

'

'

'25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long_Term_Debt_Schedule_of_Mat

Long Term Debt - Schedule of Maturities of Long-Term Debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
Total Long-Term Debt	$2,923.80	$2,975.40
TECO Finance [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
Total Long-Term Debt	1,041.20	1,041.20
Tampa Electric Company [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
2014	83.3	'
2015	83.3	'
2016	83.4	'
2017	0	'
2018	254.2	'
Thereafter	1,146.70	'
Total Long-Term Debt	1,650.90	1,702.50
PGS [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
Total Long-Term Debt	231.7	231.7
Debt Maturities [Member] | TECO Finance [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
2014	0	'
2015	191.2	'
2016	250	'
2017	300	'
2018	0	'
Thereafter	300	'
Total Long-Term Debt	1,041.20	'
Debt Maturities [Member] | Tampa Electric Company [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
2014	83.3	'
2015	83.3	'
2016	83.4	'
2017	0	'
2018	254.2	'
Thereafter	1,146.70	'
Total Long-Term Debt	1,650.90	'
Debt Maturities [Member] | PGS [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
2014	0	'
2015	0	'
2016	0	'
2017	0	'
2018	50	'
Thereafter	181.7	'
Total Long-Term Debt	231.7	'
Debt Maturities [Member] | TECO Energy [Member]	'	'
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'
2014	83.3	'
2015	274.5	'
2016	333.4	'
2017	300	'
2018	304.2	'
Thereafter	1,628.40	'
Total Long-Term Debt	$2,923.80	'

Long_Term_Debt_Schedule_of_Lon

Long Term Debt - Schedule of Long Term Debt Outstanding (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Long-term debt, total	$2,923.80	$2,975.40
Unamortized debt discount, net	-2.7	-2.7
Long-term debt, carrying amount	2,921.10	2,972.70
Less amount due within one year	83.3	0
Total long-term debt	2,837.80	2,972.70
Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	1,650.90	1,702.50
Less amount due within one year	83.3	0
Total long-term debt	1,797.50	1,932.60
TECO Finance [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	1,041.20	1,041.20
PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	231.7	231.7
Variable Rate Bonds Repurchased In 2008 [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2020	'
Long-term debt, total	0	0
6.75% Notes [Member] | TECO Finance [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2015	'
Long-term debt, total	191.2	191.2
4.00% Notes [Member] | TECO Finance [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2016	'
Long-term debt, total	250	250
6.752% Notes [Member] | TECO Finance [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2017	'
Long-term debt, total	300	300
5.15% Notes [Member] | TECO Finance [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2020	'
Long-term debt, total	300	300
5.65% Refunding bonds [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	54.2	54.2
5.15% Refunding bonds [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2025	'
Long-term debt, total	0	51.6
1.5% term rate bonds repurchased in 2011 [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2030	'
Long-term debt, total	0	0
5.0% Refunding bonds [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2034	'
Long-term debt, total	0	0
6.25% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Maturity range start	'2014	'
Due	'2016	'
Long-term debt, total	250	250
6.1% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	200	200
6.1% Notes [Member] | PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	50	50
5.4% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2021	'
Long-term debt, total	231.7	231.7
5.4% Notes [Member] | PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2021	'
Long-term debt, total	46.7	46.7
2.6% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2022	'
Long-term debt, total	225	225
2.6% Notes [Member] | PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2022	'
Long-term debt, total	25	25
6.55% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2036	'
Long-term debt, total	250	250
6.15% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2037	'
Long-term debt, total	190	190
6.15% Notes [Member] | PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2037	'
Long-term debt, total	60	60
4.1% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2042	'
4.1% Notes [Member] | Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	250	250
4.1% Notes [Member] | PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2042	'
Long-term debt, total	$50	$50

Long_Term_Debt_Schedule_of_Lon1

Long Term Debt - Schedule of Long Term Debt Outstanding (Parenthetical) (Detail) (USD $)

Mar. 31, 2008

Sep. 30, 2013

Mar. 31, 2011

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2013

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

TECO Finance [Member]

TECO Finance [Member]

TECO Finance [Member]

TECO Finance [Member]

PGS [Member]

PGS [Member]

PGS [Member]

PGS [Member]

PGS [Member]

Variable Rate Bonds Repurchased In 2008 [Member]

Refunding Bonds Repurchased In 2013 [Member]

Term Rate Bonds Repurchased In 2012 [Member]

Refunding Bonds Repurchased In 2012 [Member]

5.65% Refunding bonds [Member]

5.15% Refunding bonds [Member]

5.15% Refunding bonds [Member]

5.15% Refunding bonds [Member]

1.5% term rate bonds repurchased in 2011 [Member]

1.5% term rate bonds repurchased in 2011 [Member]

5.0% Refunding bonds [Member]

6.25% Notes [Member]

6.1% Notes [Member]

5.4% Notes [Member]

2.6% Notes [Member]

6.55% Notes [Member]

6.15% Notes [Member]

4.1% Notes [Member]

6.75% Notes [Member]

4.00% Notes [Member]

6.752% Notes [Member]

5.15% Notes [Member]

6.1% Notes [Member]

5.4% Notes [Member]

2.6% Notes [Member]

6.15% Notes [Member]

4.1% Notes [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Effective interest rate

'

'

'

'

5.90%

'

5.40%

'

'

'

0.00%

6.30%

6.00%

5.40%

2.70%

6.60%

6.20%

4.20%

6.90%

4.20%

7.30%

5.30%

7.00%

5.40%

2.70%

6.20%

4.20%

Stated interest rate

'

'

'

'

5.65%

5.15%

'

'

1.50%

'

5.00%

6.25%

6.10%

5.40%

2.60%

6.55%

6.15%

4.10%

6.75%

4.00%

6.57%

5.15%

6.10%

5.40%

2.60%

6.15%

4.10%

Repurchased bonds, par amount

$20

$51.60

$75

$86

'

'

'

$51.60

'

$75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred_Stock_Additional_Inf

Preferred Stock - Additional Information (Detail) (USD $)	Dec. 31, 2013
In Millions, except Per Share data, unless otherwise specified
Preferred Stock Par Value [Member]	'
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]	'
Preferred stock, par value	$1
Preferred stock, shares authorized	10
Preferred stock, shares outstanding	0
Preferred Stock Par Value [Member] | Tampa Electric Company [Member]	'
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]	'
Preferred stock, par value	$100
Preferred stock, shares authorized	1.5
Preferred stock, shares outstanding	0
Preferred Stock No Par Value [Member] | Tampa Electric Company [Member]	'
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]	'
Preferred stock, no par value	'
Preferred stock, shares authorized	2.5
Preferred stock, shares outstanding	0
Preference Stock (Subordinated Preferred Stock) Of Tampa Electric - No Par [Member] | Tampa Electric Company [Member]	'
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]	'
Preferred stock, no par value	'
Preferred stock, shares authorized	2.5
Preferred stock, shares outstanding	0

Common_Stock_Additional_Inform

Common Stock - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Non-vested awards compensation costs, period for recognition	'2 years	'	'
Actual restricted shares granted	700,000	1,000,000	800,000
Granted, weighted average grant date fair value	$17.21	$15.96	$18.44
Total fair market value of awards vesting	$3.50	$14.30	$13.40
Unrecognized compensation cost related to all non-vested awards	15.5	'	'
Aggregate intrinsic value of stock options exercised	2.4	0.3	1.5
Cash received from all option exercises	6.7	1.1	5
Income tax benefit realized from stock option exercises	$0.80	$0.10	$0.60
Maximum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Percentage of performance based grants can vest	150.00%	'	'
Minimum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Percentage of performance based grants can vest	0.00%	'	'
2010 Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Reduction in number of shares of common stock subject to grants	3,000,000	'	'
Common stock subject to grant	4,000,000	'	'
Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Non-vested awards compensation costs, period for recognition	'3 years	'	'
Director Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Time-vested restricted stock granted to directors, vesting period	'1 year	'	'

Common_Stock_Schedule_of_Assum

Common Stock - Schedule of Assumptions Used to Determine Fair Value (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'	'
Risk-free interest rate	0.41%	0.38%	0.96%
Expected lives (in years)	'3 years	'3 years	'3 years
Expected stock volatility	19.04%	20.99%	34.61%
Dividend yield	4.83%	4.78%	4.48%

Common_Stock_Schedule_of_Addit

Common Stock - Schedule of Additional Information on Compensation Costs and Income Tax Benefits and Excess Tax Benefits Related to Stock-Based Compensation Awards (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'	'
Compensation costs	$13.50	$12	$9.10
Income tax benefits	5.2	4.6	3.5
Excess tax benefits	$0	$2.60	$1.70

Common_Stock_Summary_of_NonVes

Common Stock - Summary of Non-Vested Shares of Restricted Stock (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Granted, Number of Shares	700	1,000	800
Granted, weighted average grant date fair value	$17.21	$15.96	$18.44
Time-Based Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Nonvested balance at Dec. 31, 2012, Number of Shares	592	'	'
Granted, Number of Shares	237	'	'
Vested, Number of Shares	-187	'	'
Forfeited, Number of Shares	-4	'	'
Nonvested balance at Dec. 31, 2013, Number of Shares	638	'	'
Nonvested balance at Dec. 31, 2012, Weighted Average Grant Date Fair Value	$18.04	'	'
Granted, weighted average grant date fair value	$17.92	'	'
Vested, Weighted Average Grant Date Fair Value	$16.91	'	'
Forfeited, Weighted Average Grant Date Fair Value	$17.99	'	'
Nonvested balance at Dec. 31, 2013, Weighted Average Grant Date Fair Value	$18.33	'	'
Performance-Based Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Nonvested balance at Dec. 31, 2012, Number of Shares	1,490	'	'
Granted, Number of Shares	496	'	'
Vested, Number of Shares	-434	'	'
Forfeited, Number of Shares	-47	'	'
Nonvested balance at Dec. 31, 2013, Number of Shares	1,505	1,490	'
Nonvested balance at Dec. 31, 2012, Weighted Average Grant Date Fair Value	$17.04	$17.13	'
Granted, weighted average grant date fair value	'	$16.87	'
Vested, Weighted Average Grant Date Fair Value	'	$17.20	'
Forfeited, Weighted Average Grant Date Fair Value	'	$16.82	'
Nonvested balance at Dec. 31, 2013, Weighted Average Grant Date Fair Value	'	$17.04	'

Common_Stock_Summary_of_NonVes1

Common Stock - Summary of Non-Vested Shares of Restricted Stock (Parenthetical) (Detail) (Restricted Stock [Member])	12 Months Ended
	Dec. 31, 2013
Restricted Stock [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Weighted average remaining contractual term of restricted stock, years	'2 years

Common_Stock_Summary_of_Stock_

Common Stock - Summary of Stock Option Transactions (Detail) (USD $)	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2013
Schedule Of Stock Options [Line Items]	'
Outstanding balance at Dec. 31, 2013, Number of Shares	1,567
Outstanding balance at Dec. 31, 2013, Weighted Avg. Option Price (per share)	$15.62
Outstanding balance at Dec. 31, 2013, Weighted Avg. Remaining Contractual Term	'2 years
Stock Options [Member]	'
Schedule Of Stock Options [Line Items]	'
Outstanding balance at Dec. 31, 2012, Number of Shares	2,087
Outstanding balance, Number of Shares	0
Exercised, Number of Shares	-507
Cancelled, Number of Shares	-13
Outstanding balance at Dec. 31, 2013, Number of Shares	1,567
Exercisable at Dec. 31, 2013, Number of Shares	1,567
Available for future grant at Dec. 31, 2013, Number of Shares	2,725
Outstanding balance at Dec. 31, 2012, Weighted Avg. Option Price (per share)	$15.05
Granted, Weighted Avg. Option Price	$0
Exercised, Weighted Avg. Option Price	$13.22
Cancelled, Weighted Avg. Option Price	$18.87
Outstanding balance at Dec. 31, 2013, Weighted Avg. Option Price (per share)	$15.62
Exercisable at Dec. 31, 2013, Weighted Avg. Option Price	$15.62
Outstanding balance at Dec. 31, 2013, Weighted Avg. Remaining Contractual Term	'2 years
Exercisable at Dec. 31, 2013, Weighted Avg. Remaining Contractual Term	'2 years
Outstanding balance at Dec. 31, 2013, Aggregate Intrinsic Value	$2.60
Exercisable at Dec. 31, 2013, Aggregate Intrinsic Value	$2.60

Common_Stock_Summary_of_Stock_1

Common Stock - Summary of Stock Option Transactions (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Range of Option Prices, Minimum	$12.01
Range of Option Prices, Maximum	$19.01

Common_Stock_Schedule_of_Optio

Common Stock - Schedule of Option Outstanding and Exercisable (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Range of Option Prices, Minimum	$12.01
Range of Option Prices, Maximum	$19.01
Option Shares	1,567
Weighted-Avg. Option Price	$15.62
Weighted-Avg. Remaining Contractual Life, Years	'2 years
$12.01 - $13.56 [Member]	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Range of Option Prices, Minimum	$12.01
Range of Option Prices, Maximum	$13.56
Option Shares	331
Weighted-Avg. Option Price	$13.10
Weighted-Avg. Remaining Contractual Life, Years	'1 year
$16.21 - $19.01 [Member]	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Range of Option Prices, Minimum	$16.21
Range of Option Prices, Maximum	$19.01
Option Shares	1,236
Weighted-Avg. Option Price	$16.29
Weighted-Avg. Remaining Contractual Life, Years	'2 years

Other_Comprehensive_Income_Oth

Other Comprehensive Income - Other Comprehensive Income (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Comprehensive Income Loss [Line Items]	'	'	'
Unrealized gain (loss) on cash flow hedges, Gross	$1	($7.40)	$1.80
Reclassification from AOCI to net income, Gross	1.3	0.6	-3.1
Gain (Loss) Gain on cash flow hedges, Gross	2.3	-6.8	-1.3
Amortization of unrecognized benefit costs and other, Gross	23.6	-4.8	-7.9
Recognized benefit costs due to settlement, Gross	2.6	'	0.9
Total other comprehensive (loss) income, Gross	28.5	-11.6	-8.3
Unrealized gain (loss) on cash flow hedges, Tax	-0.4	2.8	-0.6
Reclassification from AOCI to net income, Tax	-0.5	-0.2	1.1
Gain (Loss) on cash flow hedges, Tax	-0.9	2.6	0.5
Amortization of unrecognized benefit costs and other, Tax	-8.8	0	3.3
Recognized benefit costs due to settlement, Tax	-1	'	-0.3
Total other comprehensive (loss) income, Tax	-10.7	2.6	3.5
Unrealized gain (loss) on cash flow hedges, Net	0.6	-4.6	1.2
Reclassification from AOCI to net income, Net	0.8	0.4	-2
Gain (Loss) on cash flow hedges, Net	1.4	-4.2	-0.8
Amortization of unrecognized benefit costs and other, Net	14.8	-4.8	-4.6
Recognized benefit costs due to settlement, Net	1.6	'	0.6
Other comprehensive income (loss), net of tax	17.8	-9	-4.8
Tampa Electric Company [Member]	'	'	'
Other Comprehensive Income Loss [Line Items]	'	'	'
Unrealized gain (loss) on cash flow hedges, Gross	0	-8	0
Reclassification from AOCI to net income, Gross	1.4	1.4	1.2
Gain (Loss) Gain on cash flow hedges, Gross	1.4	-6.6	1.2
Total other comprehensive (loss) income, Gross	1.4	-6.6	1.2
Unrealized gain (loss) on cash flow hedges, Tax	0	3.1	0
Reclassification from AOCI to net income, Tax	-0.5	-0.6	-0.5
Gain (Loss) on cash flow hedges, Tax	-0.5	2.5	-0.5
Total other comprehensive (loss) income, Tax	-0.5	2.5	-0.5
Unrealized gain (loss) on cash flow hedges, Net	0	-4.9	0
Reclassification from AOCI to net income, Net	0.9	0.8	0.7
Gain (Loss) on cash flow hedges, Net	0.9	-4.1	0.7
Other comprehensive income (loss), net of tax	$0.90	($4.10)	$0.70

Other_Comprehensive_Income_Acc

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Net unrealized losses from cash flow hedges	($7.80)	($9.20)
Total accumulated other comprehensive loss	-13.2	-31
Pension Benefits [Member]	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Unrecognized other benefit gains, prior service costs and transition obligations	-20.5	-32.9
Other Postretirement Benefits [Member]	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Unrecognized other benefit gains, prior service costs and transition obligations	15.1	11.1
Tampa Electric Company [Member]	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Net unrealized losses from cash flow hedges	-7.8	-8.7
Total accumulated other comprehensive loss	($7.80)	($8.70)

Other_Comprehensive_Income_Acc1

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Net unrealized losses from cash flow hedges, tax benefit	$4.90	$5.80
Pension Benefits [Member]	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Unrecognized pension and other benefit gain (loss), prior service cost (credit) and transition obligation, tax expense (benefit)	12.6	20.1
Other Postretirement Benefits [Member]	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Unrecognized pension and other benefit gain (loss), prior service cost (credit) and transition obligation, tax expense (benefit)	9.1	6.7
Tampa Electric Company [Member]	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'
Net unrealized losses from cash flow hedges, tax benefit	$4.90	$5.50

Earnings_Per_Share_Schedule_of

Earnings Per Share - Schedule of Earnings Per Share (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basic earnings per share	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations	$42.10	$62.90	$51.60	$41.20	$45.60	$90.20	$65.60	$44.60	$197.80	$246	$250.80
Amount allocated to nonvested participating shareholders	'	'	'	'	'	'	'	'	-0.6	-0.8	-1.3
Income before discontinued operations available to common shareholders - Basic	'	'	'	'	'	'	'	'	197.2	245.2	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	'	'	'	'	'	'	'	'	-0.1	-33.3	21.8
Amount allocated to nonvested participating shareholders	'	'	'	'	'	'	'	'	0	0.1	-0.1
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic	'	'	'	'	'	'	'	'	-0.1	-33.2	21.7
Net income attributable to TECO Energy	42	62.8	51.4	41.5	45.1	44	73.1	50.5	197.7	212.7	272.6
Amount allocated to nonvested participating shareholders	'	'	'	'	'	'	'	'	-0.6	-0.7	-1.4
Net income attributable to TECO Energy available to common shareholders - Basic	'	'	'	'	'	'	'	'	197.1	212	271.2
Average common shares outstanding - Basic	'	'	'	'	'	'	'	'	215	214.3	213.6
Earnings per share from continuing operations available to common shareholders - Basic	$0.20	$0.29	$0.24	$0.19	$0.21	$0.42	$0.30	$0.21	$0.92	$1.14	$1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	'	'	'	'	'	'	'	'	$0	($0.15)	$0.10
Earnings per share attributable to TECO Energy available to common shareholders - Basic	'	'	'	'	'	'	'	'	$0.92	$0.99	$1.27
Diluted earnings per share	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations	42.1	62.9	51.6	41.2	45.6	90.2	65.6	44.6	197.8	246	250.8
Amount allocated to nonvested participating shareholders	'	'	'	'	'	'	'	'	-0.6	-0.8	-1.3
Income before discontinued operations available to common shareholders - Diluted	'	'	'	'	'	'	'	'	197.2	245.2	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	'	'	'	'	'	'	'	'	-0.1	-33.3	21.8
Amount allocated to nonvested participating shareholders	'	'	'	'	'	'	'	'	0	0.1	-0.1
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	'	'	'	'	'	'	'	'	-0.1	-33.2	21.7
Net income attributable to TECO Energy	42	62.8	51.4	41.5	45.1	44	73.1	50.5	197.7	212.7	272.6
Amount allocated to nonvested participating shareholders	'	'	'	'	'	'	'	'	-0.6	-0.7	-1.4
Net income attributable to TECO Energy available to common shareholders - Diluted	'	'	'	'	'	'	'	'	$197.10	$212	$271.20
Unadjusted average common shares outstanding - Diluted	'	'	'	'	'	'	'	'	215	214.3	213.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net	'	'	'	'	'	'	'	'	0.5	0.7	1.5
Average common shares outstanding - Diluted	'	'	'	'	'	'	'	'	215.5	215	215.1
Earnings per share from continuing operations available to common shareholders - Diluted	$0.20	$0.29	$0.24	$0.19	$0.21	$0.42	$0.30	$0.20	$0.92	$1.14	$1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	'	'	'	'	'	'	'	'	$0	($0.15)	$0.10
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	'	'	'	'	'	'	'	'	$0.92	$0.99	$1.27
Anti-dilutive shares	'	'	'	'	'	'	'	'	0	0.4	1.7

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended			6 Months Ended	12 Months Ended			11 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Nov. 30, 2010	Dec. 31, 2013
				Tampa Electric Company [Member]	Tampa Electric Company [Member]	Tampa Electric Company [Member]	Tampa Electric Company [Member]	PGS [Member]	PGS [Member]
				Plaintiff				Plaintiff
Long Term Commitments [Line Items]	'	'	'	'	'	'	'	'	'
Number of commercial PGS customers filing on behalf of PGS customers	'	'	'	3	'	'	'	2	'
Ultimate financial liability to superfund sites and former MGP sites	'	'	'	'	'	'	'	'	$40.40
Total rental expense and leases	7.6	8.1	10.2	'	2.3	2.2	2.2	'	'
Letters of Credit Outstanding	$0.70	$1.50	'	'	$0.70	$1.50	'	'	'

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Lease Payments (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Long Term Commitments [Line Items]	'
Future Minimum Lease and Capacity Payments, 2014	$19.80
Future Minimum Lease and Capacity Payments, 2015	18.8
Future Minimum Lease and Capacity Payments, 2016	17.2
Future Minimum Lease and Capacity Payments, 2017	12.3
Future Minimum Lease and Capacity Payments, 2018	12.3
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	93.8
Tampa Electric Company [Member]	'
Long Term Commitments [Line Items]	'
Future Minimum Lease and Capacity Payments, 2014	17.1
Future Minimum Lease and Capacity Payments, 2015	17.2
Future Minimum Lease and Capacity Payments, 2016	16.8
Future Minimum Lease and Capacity Payments, 2017	12.1
Future Minimum Lease and Capacity Payments, 2018	12.3
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	88.9
Capacity Payments [Member]	'
Long Term Commitments [Line Items]	'
Future Minimum Lease and Capacity Payments, 2014	14.8
Future Minimum Lease and Capacity Payments, 2015	14.9
Future Minimum Lease and Capacity Payments, 2016	14.6
Future Minimum Lease and Capacity Payments, 2017	9.9
Future Minimum Lease and Capacity Payments, 2018	10.1
Future Minimum Lease and Capacity Payments, Thereafter	0
Total future minimum payments	64.3
Capacity Payments [Member] | Tampa Electric Company [Member]	'
Long Term Commitments [Line Items]	'
Future Minimum Lease and Capacity Payments, 2014	14.8
Future Minimum Lease and Capacity Payments, 2015	14.9
Future Minimum Lease and Capacity Payments, 2016	14.6
Future Minimum Lease and Capacity Payments, 2017	9.9
Future Minimum Lease and Capacity Payments, 2018	10.1
Future Minimum Lease and Capacity Payments, Thereafter	0
Total future minimum payments	64.3
Operating Leases [Member]	'
Long Term Commitments [Line Items]	'
Future Minimum Lease and Capacity Payments, 2014	5
Future Minimum Lease and Capacity Payments, 2015	3.9
Future Minimum Lease and Capacity Payments, 2016	2.6
Future Minimum Lease and Capacity Payments, 2017	2.4
Future Minimum Lease and Capacity Payments, 2018	2.2
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	29.5
Operating Leases [Member] | Tampa Electric Company [Member]	'
Long Term Commitments [Line Items]	'
Future Minimum Lease and Capacity Payments, 2014	2.3
Future Minimum Lease and Capacity Payments, 2015	2.3
Future Minimum Lease and Capacity Payments, 2016	2.2
Future Minimum Lease and Capacity Payments, 2017	2.2
Future Minimum Lease and Capacity Payments, 2018	2.2
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	$24.60

Commitments_and_Contingencies_3

Commitments and Contingencies - Letters of Credit and Guarantees (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Guarantor Obligations [Line Items]	'
2014	$10.80
2015-2018	5.7
After 2018	95.8
Total	112.3
Liabilities Recognized at Dec. 31, 2013	6.6
2014	10.8
2015-2018	5.7
After 2018	95.8
Total	112.3
Liabilities Recognized at Dec. 31, 2013	6.6
Tampa Electric Company [Member] | Letters of Credit [Member]	'
Guarantor Obligations [Line Items]	'
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Dec. 31, 2013	0.1
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Dec. 31, 2013	0.1
TECO Coal [Member] | Fuel Purchase Related [Member]	'
Guarantor Obligations [Line Items]	'
2014	0.8
2015-2018	0.7
After 2018	4
Total	5.5
Liabilities Recognized at Dec. 31, 2013	1.5
2014	0.8
2015-2018	0.7
After 2018	4
Total	5.5
Liabilities Recognized at Dec. 31, 2013	1.5
Other Subsidiaries [Member] | Guaranty Under Sale Agreement [Member]	'
Guarantor Obligations [Line Items]	'
2014	0
2015-2018	5
After 2018	0
Total	5
Liabilities Recognized at Dec. 31, 2013	5
2014	0
2015-2018	5
After 2018	0
Total	5
Liabilities Recognized at Dec. 31, 2013	5
Other Subsidiaries [Member] | Fuel Sales And Transportation [Member]	'
Guarantor Obligations [Line Items]	'
2014	10
2015-2018	0
After 2018	91.8
Total	101.8
Liabilities Recognized at Dec. 31, 2013	0.1
2014	10
2015-2018	0
After 2018	91.8
Total	101.8
Liabilities Recognized at Dec. 31, 2013	$0.10

Related_Parties_Additional_Inf

Related Parties - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Legal fees	$1.70	$1.30	$1.30
Tampa Electric Company [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Legal fees	$1.70	$1.20	$1.30

Related_Parties_Schedule_of_Re

Related Parties - Schedule of Related Parties (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Natural gas sales, net	$18.30	$11.70	$0
Administrative and general, net	27.2	23.4	17.5
Tampa Electric Company [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Accounts receivable	1.3	4.7	'
Accounts payable	9.8	7.9	'
Taxes receivable	54.9	22.1	'
Taxes payable	$0.40	$3.20	'

Segment_Information_Schedule_o

Segment Information - Schedule of Segment Information (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	$688.40	$765.90	$735.90	$661.10	$688.40	$858.60	$752.50	$697.10	$2,851.30	$2,996.60	$3,209.90
Depreciation and amortization	'	'	'	'	'	'	'	'	329.5	330.6	317.2
Total interest charges	'	'	'	'	'	'	'	'	166.9	183.5	197.4
Internally allocated interest	'	'	'	'	'	'	'	'	0	0	0
Provision for income taxes	'	'	'	'	'	'	'	'	108.9	137.8	142.7
Net income from continuing operations	42.1	62.9	51.6	41.2	45.6	90.2	65.6	44.6	197.8	246	250.8
Discontinued operations attributable to TECO, net of tax	'	'	'	'	'	'	'	'	-0.1	-33.3	21.8
Net income	42	62.8	51.4	41.5	45.1	44	73.1	50.5	197.7	212.7	272.6
Total assets	7,448	'	'	'	7,334.90	'	'	'	7,448	7,334.90	7,307.20
Capital expenditures	'	'	'	'	'	'	'	'	532.4	505.1	454.1
Goodwill	'	'	'	'	0	'	'	'	'	0	55.4
Other & Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	11.1	7.5	2.8
Depreciation and amortization	'	'	'	'	'	'	'	'	1.5	1.4	1.4
Total interest charges	'	'	'	'	'	'	'	'	56.1	50.6	51
Internally allocated interest	'	'	'	'	'	'	'	'	-6.4	-6.8	-6.7
Provision for income taxes	'	'	'	'	'	'	'	'	-26.3	-19.6	-18.1
Net income from continuing operations	'	'	'	'	'	'	'	'	-36.8	-31.4	-36
Discontinued operations attributable to TECO, net of tax	'	'	'	'	'	'	'	'	-0.1	-4	-0.6
Net income	'	'	'	'	'	'	'	'	-36.9	-35.4	-36.6
Total assets	-16.4	'	'	'	-238.8	'	'	'	-16.4	-238.8	-240
Capital expenditures	'	'	'	'	'	'	'	'	2.4	1.2	3.5
Goodwill	'	'	'	'	'	'	'	'	'	'	0
Revenues - External [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	2,851.30	2,996.60	3,209.90
Revenues - External [Member] | Other & Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	12.8	10.4	7.1
Sales to Affiliates [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0	0	0
Sales to Affiliates [Member] | Other & Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	-1.7	-2.9	-4.3
Tampa Electric [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	1,950.50	1,981.30	2,020.60
Depreciation and amortization	'	'	'	'	'	'	'	'	238.8	237.6	222.1
Total interest charges	'	'	'	'	'	'	'	'	91.8	109.8	121.8
Internally allocated interest	'	'	'	'	'	'	'	'	0	0	0
Provision for income taxes	'	'	'	'	'	'	'	'	116.9	120.2	124.8
Net income from continuing operations	'	'	'	'	'	'	'	'	190.9	193.1	202.7
Discontinued operations attributable to TECO, net of tax	'	'	'	'	'	'	'	'	0	0	0
Net income	'	'	'	'	'	'	'	'	190.9	193.1	202.7
Total assets	6,126.90	'	'	'	6,042.30	'	'	'	6,126.90	6,042.30	5,925.90
Capital expenditures	'	'	'	'	'	'	'	'	428.6	361.7	314.9
Goodwill	'	'	'	'	'	'	'	'	'	'	0
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	1,949.60	1,980.70	2,019.30
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0.9	0.6	1.3
PGS [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	393.5	398.9	453.5
Depreciation and amortization	'	'	'	'	'	'	'	'	51.5	50.6	48.4
Total interest charges	'	'	'	'	'	'	'	'	13.5	16	17.7
Internally allocated interest	'	'	'	'	'	'	'	'	0	0	0
Provision for income taxes	'	'	'	'	'	'	'	'	21.9	21.5	20.6
Net income from continuing operations	'	'	'	'	'	'	'	'	34.7	34.1	32.6
Discontinued operations attributable to TECO, net of tax	'	'	'	'	'	'	'	'	0	0	0
Net income	'	'	'	'	'	'	'	'	34.7	34.1	32.6
Total assets	1,021.20	'	'	'	1,009.90	'	'	'	1,021.20	1,009.90	932
Capital expenditures	'	'	'	'	'	'	'	'	79	97.3	71.9
Goodwill	'	'	'	'	'	'	'	'	'	'	0
PGS [Member] | Revenues - External [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	392.7	396.6	450.5
PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0.8	2.3	3
TECO Coal [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	496.2	608.9	733
Depreciation and amortization	'	'	'	'	'	'	'	'	37.7	41	45.3
Total interest charges	'	'	'	'	'	'	'	'	5.5	7.1	6.9
Internally allocated interest	'	'	'	'	'	'	'	'	6.4	6.8	6.7
Provision for income taxes	'	'	'	'	'	'	'	'	-3.6	15.7	15.4
Net income from continuing operations	'	'	'	'	'	'	'	'	9	50.2	51.5
Discontinued operations attributable to TECO, net of tax	'	'	'	'	'	'	'	'	0	0	0
Net income	'	'	'	'	'	'	'	'	9	50.2	51.5
Total assets	316.3	'	'	'	356.6	'	'	'	316.3	356.6	385.2
Capital expenditures	'	'	'	'	'	'	'	'	22.4	36.3	56.6
Goodwill	'	'	'	'	'	'	'	'	'	'	0
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	496.2	608.9	733
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0	0	0
TECO Guatemala [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	0	0	0
Depreciation and amortization	'	'	'	'	'	'	'	'	0	0	0
Total interest charges	'	'	'	'	'	'	'	'	0	0	0
Internally allocated interest	'	'	'	'	'	'	'	'	0	0	0
Provision for income taxes	'	'	'	'	'	'	'	'	0	0	0
Net income from continuing operations	'	'	'	'	'	'	'	'	0	0	0
Discontinued operations attributable to TECO, net of tax	'	'	'	'	'	'	'	'	0	-29.3	22.4
Net income	'	'	'	'	'	'	'	'	0	-29.3	22.4
Total assets	0	'	'	'	164.9	'	'	'	0	164.9	304.1
Capital expenditures	'	'	'	'	'	'	'	'	0	8.6	7.2
Goodwill	'	'	'	'	'	'	'	'	'	'	55.4
TECO Guatemala [Member] | Revenues - External [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	0	0	0
TECO Guatemala [Member] | Sales to Affiliates [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0	0	0
Tampa Electric Company [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	2,342.80	2,378	2,470.60
Depreciation and amortization	'	'	'	'	'	'	'	'	290.3	288.2	270.5
Total interest charges	'	'	'	'	'	'	'	'	105.3	125.8	139.5
Provision for income taxes	'	'	'	'	'	'	'	'	138.8	141.7	145.4
Net income	'	'	'	'	'	'	'	'	225.6	227.2	235.3
Total assets	6,875.80	'	'	'	6,744.60	'	'	'	6,875.80	6,744.60	6,556.40
Capital expenditures	'	'	'	'	'	'	'	'	507.6	459	386.8
Tampa Electric Company [Member] | Other & Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	-1.2	-2.2	-3.5
Depreciation and amortization	'	'	'	'	'	'	'	'	0	0	0
Total interest charges	'	'	'	'	'	'	'	'	0	0	0
Provision for income taxes	'	'	'	'	'	'	'	'	0	0	0
Net income	'	'	'	'	'	'	'	'	0	0	0
Total assets	-8.9	'	'	'	13.3	'	'	'	-8.9	13.3	-10
Capital expenditures	'	'	'	'	'	'	'	'	0	0	0
Tampa Electric Company [Member] | Revenues - External [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	2,342.80	2,378	2,470.60
Tampa Electric Company [Member] | Revenues - External [Member] | Other & Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	0	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member] | Other & Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	-1.2	-2.2	-3.5
Tampa Electric Company [Member] | Tampa Electric [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	1,950.50	1,981.30	2,020.60
Depreciation and amortization	'	'	'	'	'	'	'	'	238.8	237.6	222.1
Total interest charges	'	'	'	'	'	'	'	'	91.8	109.8	121.8
Provision for income taxes	'	'	'	'	'	'	'	'	116.9	120.2	124.8
Net income	'	'	'	'	'	'	'	'	190.9	193.1	202.7
Total assets	5,895.40	'	'	'	5,760.40	'	'	'	5,895.40	5,760.40	5,678
Capital expenditures	'	'	'	'	'	'	'	'	428.6	361.7	314.9
Tampa Electric Company [Member] | Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	1,950.10	1,980.90	2,020.10
Tampa Electric Company [Member] | Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	0.4	0.4	0.5
Tampa Electric Company [Member] | PGS [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	393.5	398.9	453.5
Depreciation and amortization	'	'	'	'	'	'	'	'	51.5	50.6	48.4
Total interest charges	'	'	'	'	'	'	'	'	13.5	16	17.7
Provision for income taxes	'	'	'	'	'	'	'	'	21.9	21.5	20.6
Net income	'	'	'	'	'	'	'	'	34.7	34.1	32.6
Total assets	989.3	'	'	'	970.9	'	'	'	989.3	970.9	888.4
Capital expenditures	'	'	'	'	'	'	'	'	79	97.3	71.9
Tampa Electric Company [Member] | PGS [Member] | Revenues - External [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	392.7	397.1	450.5
Tampa Electric Company [Member] | PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales to affiliates	'	'	'	'	'	'	'	'	$0.80	$1.80	$3

Segment_Information_Schedule_o1

Segment Information - Schedule of Segment Information (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting [Abstract]	'	'	'
Internally allocated interest costs, pre tax rate	6.00%	6.00%	6.25%
Capital structure assumption, debt to equity ratio	50.00%	'	'
Mineral rights	$12.10	$13.40	$15

Segment_Information_Additional

Segment Information - Additional Information (Detail)	Dec. 31, 2013
	Customer
Tampa Electric [Member]	'
Segment Reporting Information [Line Items]	'
Number of retail electric utility service customers in West Central Florida	700,000
Tampa Electric [Member] | Tampa Electric Company [Member]	'
Segment Reporting Information [Line Items]	'
Number of retail electric utility service customers in West Central Florida	700,000
PGS [Member] | Minimum [Member]	'
Segment Reporting Information [Line Items]	'
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	350,000
PGS [Member] | Minimum [Member] | Tampa Electric Company [Member]	'
Segment Reporting Information [Line Items]	'
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	350,000

Asset_Retirement_Obligations_A

Asset Retirement Obligations - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Line Items]	'	'	'
Obligations arise from environmental remediation	$28.60	$28.60	$53.80
Accretion expense	1.4	1.4	1.4
Liabilities settled	1.4	29.1	'
Tampa Electric Company [Member]	'	'	'
Asset Retirement Obligation [Line Items]	'	'	'
Obligations arise from environmental remediation	4.8	5	30.8
Cost of removal or dismantling of assets charged to regulatory liability	4.8	5	'
Liabilities settled	0.2	27.6	'
TECO Energy [Member]	'	'	'
Asset Retirement Obligation [Line Items]	'	'	'
Obligations arise from environmental remediation	$23.80	$23.60	'

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Line Items]	'	'	'
Beginning balance	$28.60	$53.80	'
Additional liabilities	0.1	0.7	'
Liabilities settled	-1.4	-29.1	'
Accretion expense	1.4	1.4	1.4
Revisions to estimated cash flows	-0.3	0	'
Other	0.2	1.8	'
Ending balance	28.6	28.6	53.8
Tampa Electric Company [Member]	'	'	'
Asset Retirement Obligation [Line Items]	'	'	'
Beginning balance	5	30.8	'
Additional liabilities	0.1	0	'
Liabilities settled	-0.2	-27.6	'
Revisions to estimated cash flows	-0.3	0	'
Other	0.2	1.8	'
Ending balance	$4.80	$5	'

Accounting_for_Derivative_Inst2

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Cash Flow Hedges (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Current assets	$9.70	$0
Long-term assets	0.3	0.2
Total assets	10	0.2
Current liabilities	0.1	14.6
Long-term liabilities	0.2	0.6
Total liabilities	0.3	15.2
Tampa Electric Company [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current assets	9.5	0
Long-term assets	0.3	0.2
Current liabilities	0	14.1
Long-term liabilities	0.2	0.2
Diesel Fuel Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current assets	0.2	0
Long-term assets	0	0
Total assets	0.2	0
Current liabilities	0.1	0.5
Long-term liabilities	0	0.4
Total liabilities	0.1	0.9
Natural Gas Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current assets	9.5	0
Long-term assets	0.3	0.2
Total assets	9.8	0.2
Current liabilities	0	14.1
Long-term liabilities	0.2	0.2
Total liabilities	0.2	14.3
Natural Gas Derivatives [Member] | Tampa Electric Company [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current assets	9.5	0
Long-term assets	0.3	0.2
Total assets	9.8	0.2
Current liabilities	0	14.1
Long-term liabilities	0.2	0.2
Total liabilities	$0.20	$14.30

Accounting_for_Derivative_Inst3

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Collateral posted with or received from any counterparties	$0	$0
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.8	9.2
Net pretax losses expected to be reclassified from regulatory assets or liabilities	9.5	'
Diesel Fuel [Member]	'	'
Derivative [Line Items]	'	'
Maximum length of time hedging in future cash flow	31-Dec-14	'
Natural Gas Contracts [Member]	'	'
Derivative [Line Items]	'	'
Maximum length of time hedging in future cash flow	31-Dec-15	'
Tampa Electric Company [Member]	'	'
Derivative [Line Items]	'	'
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.8	8.7
Net pretax losses expected to be reclassified from regulatory assets or liabilities	9.5	'
Interest Rate Swap [Member]	'	'
Derivative [Line Items]	'	'
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	$7.80	$9.20

Accounting_for_Derivative_Inst4

Accounting for Derivative Instruments and Hedging Activities - Gross Amounts of Derivatives and Their Related Offset Amounts (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Derivative assets, Gross Amounts of Recognized Assets	$10.50	$1
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	-0.8	-16
Derivative assets, Gross Amounts offset on the Balance Sheet	-0.5	-0.8
Derivative liabilities, Gross Amounts offset on the Balance Sheet	0.5	0.8
Derivative assets, Net Amounts of Assets	10	0.2
Derivative assets, Net Amounts of Liabilities	-0.3	-15.2
Tampa Electric Company [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets, Gross Amounts of Recognized Assets	10.3	1
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	-0.7	-15.1
Derivative assets, Gross Amounts offset on the Balance Sheet	-0.5	-0.8
Derivative liabilities, Gross Amounts offset on the Balance Sheet	0.5	0.8
Derivative assets, Net Amounts of Assets	9.8	0.2
Derivative assets, Net Amounts of Liabilities	($0.20)	($14.30)

Accounting_for_Derivative_Inst5

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Hedging Instruments (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Current liabilities	$0.10	$14.60
Long-term derivative liabilities	0.2	0.6
Total liabilities	0.3	15.2
Current assets	9.7	0
Long-term derivative assets	0.3	0.2
Total assets	10	0.2
Diesel Fuel Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current liabilities	0.1	0.5
Long-term derivative liabilities	0	0.4
Total liabilities	0.1	0.9
Current assets	0.2	0
Long-term derivative assets	0	0
Total assets	0.2	0
Natural Gas Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current liabilities	0	14.1
Long-term derivative liabilities	0.2	0.2
Total liabilities	0.2	14.3
Current assets	9.5	0
Long-term derivative assets	0.3	0.2
Total assets	9.8	0.2
Derivatives Designated as Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Total liabilities	0.3	15.2
Total assets	10	0.2
Derivatives Designated as Hedging Instruments [Member] | Diesel Fuel Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current liabilities	0.1	0.5
Long-term derivative liabilities	0	0.4
Current assets	0.2	0
Long-term derivative assets	0	0
Derivatives Designated as Hedging Instruments [Member] | Natural Gas Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current liabilities	0	14.1
Long-term derivative liabilities	0.2	0.2
Current assets	9.5	0
Long-term derivative assets	$0.30	$0.20

Accounting_for_Derivative_Inst6

Accounting for Derivative Instruments and Hedging Activities - Energy Related Derivatives (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Current regulatory assets	$34.30	$70.30
Long-term regulatory assets	293.1	382.6
Regulatory assets	327.4	452.9
Current regulatory liabilities	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Tampa Electric Company [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current regulatory assets	34.3	70.3
Long-term regulatory assets	293.1	382.6
Regulatory assets	327.4	452.9
Current regulatory liabilities	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Regulatory liabilities	717.2	737
Energy Related Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current regulatory assets	0	14.1
Long-term regulatory assets	0.2	0.2
Regulatory assets	0.2	14.3
Current regulatory liabilities	9.5	0
Long-term regulatory liabilities	0.3	0.2
Regulatory liabilities	9.8	0.2
Energy Related Derivatives [Member] | Tampa Electric Company [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current regulatory assets	0	14.1
Long-term regulatory assets	0.2	0.2
Regulatory assets	0.2	14.3
Current regulatory liabilities	9.5	0
Long-term regulatory liabilities	0.3	0.2
Regulatory liabilities	$9.80	$0.20

Accounting_for_Derivative_Inst7

Accounting for Derivative Instruments and Hedging Activities - Effect of Hedging Instruments on Other Comprehensive Income and Income (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$0.60	($4.60)	$1.20
Amount of Gain/(Loss) Reclassified From AOCI Into Income	-0.8	-0.4	2
Tampa Electric Company [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Amount of Gain/(Loss) Reclassified From AOCI Into Income	-0.9	-0.8	-0.7
Diesel Fuel Derivatives [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0.6	0.3	1.2
Location of Gain/(Loss) Reclassified From AOCI Into Income	'Mining related costs	'Mining related costs	'Mining related costs
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0.1	0.4	2.7
Interest rate contracts [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	-4.9	0
Location of Gain/(Loss) Reclassified From AOCI Into Income	'Interest expense	'Interest expense	'Interest expense
Amount of Gain/(Loss) Reclassified From AOCI Into Income	-0.9	-0.8	-0.7
Interest rate contracts [Member] | Tampa Electric Company [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Location of Gain/(Loss) Reclassified From AOCI Into Income	'Interest expense	'	'
Amount of Gain/(Loss) Reclassified From AOCI Into Income	($0.90)	($0.80)	($0.70)

Accounting_for_Derivative_Inst8

Accounting for Derivative Instruments and Hedging Activities - Derivative Activity for Instruments Classified as Qualifying Cash Flow Hedges (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Fair Value Asset/(Liability)	$0.10	($0.90)	($0.30)
Amount of Gain/(Loss) Recognized in OCI	0.6	-4.6	1.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	-0.8	-0.4	2
Diesel Fuel Derivatives [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Fair Value Asset/(Liability)	0.1	-0.9	-0.3
Amount of Gain/(Loss) Recognized in OCI	0.6	0.3	1.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0.1	0.4	2.7
Interest Rate Swap [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Fair Value Asset/(Liability)	0	0	0
Amount of Gain/(Loss) Recognized in OCI	0	-4.9	0
Amount of Gain/(Loss) Reclassified From AOCI Into Income	($0.90)	($0.80)	($0.70)

Accounting_for_Derivative_Inst9

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Dec. 31, 2013
	gal
Diesel Fuel Derivatives [Member] | Physical [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2015 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Financial [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,000,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,000,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2015 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | Tampa Electric Company [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2014 [Member] | Tampa Electric Company [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2015 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2015 [Member] | Tampa Electric Company [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Financial [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	44,500,000
Natural Gas Contracts [Member] | Financial [Member] | Tampa Electric Company [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	44,500,000
Natural Gas Contracts [Member] | Financial [Member] | 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	36,900,000
Natural Gas Contracts [Member] | Financial [Member] | 2014 [Member] | Tampa Electric Company [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	36,900,000
Natural Gas Contracts [Member] | Financial [Member] | 2015 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	7,600,000
Natural Gas Contracts [Member] | Financial [Member] | 2015 [Member] | Tampa Electric Company [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	7,600,000

Recovered_Sheet6

Accounting for Derivative Instruments and Hedging Activities - Fair Value of Overall Contractual Contingent Liability Positions (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'
Fair Value Asset/ (Liability)	($0.10)
Derivative Exposure Asset/ (Liability)	-0.1
Posted Collateral	$0

Fair_Value_Measurements_Schedu

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	$10	$0.20
Total Swap Liabilities	0.3	15.2
Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	10	0.2
Total Swap Liabilities	0.3	15.2
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0.2	0
Total Swap Liabilities	0.1	0.9
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	10	0.2
Total Swap Liabilities	0.3	15.2
Level 2 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Level 2 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0.2	0
Total Swap Liabilities	0.1	0.9
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Level 1 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Level 2 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Level 3 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	$0	$0

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]	'	'
Total Swap Assets	$10	$0.20
Total Swap Liabilities	0.3	15.2
Fair Value, Measurements, Recurring [Member]	'	'
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]	'	'
Total Swap Assets	10	0.2
Total Swap Liabilities	0.3	15.2
Tampa Electric Company [Member]	'	'
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]	'	'
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]	'	'
Total Swap Assets	0	0
Total Swap Liabilities	$0	$0

Variable_Interest_Entities_Add

Variable Interest Entities - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Purchased power	$64.70	$105.30	$125.90
Agreement's expiration	31-Dec-12	'	'
Tampa Electric Company [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Purchased power	64.7	105.3	125.9
Agreement's expiration	31-Dec-12	'	'
Power Purchase Agreements [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Purchased power	'	46.6	34.4
Power Purchase Agreements [Member] | Variable Interest Entities [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Purchased power	22.1	75.8	81.2
Power Purchase Agreements [Member] | Tampa Electric Company [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Purchased power	'	46.6	34.4
Power Purchase Agreements [Member] | Tampa Electric Company [Member] | Variable Interest Entities [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Purchased power	$22.10	$75.80	$81.20
Minimum [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Multiple PPAs range	117	'	'
Minimum [Member] | Tampa Electric Company [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Multiple PPAs range	117	'	'
Maximum [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Multiple PPAs range	370	'	'
Maximum [Member] | Tampa Electric Company [Member]	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Multiple PPAs range	370	'	'

Discontinued_Operations_Additi

Discontinued Operations - Additional Information (Detail) (USD $)	0 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 19, 2013	Sep. 27, 2012	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Sale of ownership interests, Disposal Group	'	$227.50	'
Percentage of ownership in TCAE by TPS GO	'	96.06%	'
Foreign tax credits	'	'	22.9
Awarded damages	21.1	'	'
Prime interest rate	2.00%	'	'
Reimburse costs incurred	7.5	'	'
TPS GO [Member]	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Sale of ownership interests, Disposal Group	'	12.5	'
TPS SJI [Member]	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Sale of ownership interests, Disposal Group	'	213.5	'
TGS [Member]	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Sale of ownership interests, Disposal Group	'	$1.50	'

Discontinued_Operations_Compon

Discontinued Operations - Components of Discontinued Operations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Income (loss) from discontinued operations	($0.20)	($10.60)	$33.30
Provision for income taxes	0.1	-22.4	-11.2
Income (loss) from discontinued operations, net	-0.1	-33	22.1
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.3	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	-0.1	-33.3	21.8
TECO Guatemala [Member]	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Revenues	0	114.2	133.5
(Loss) income from operations	-0.2	27.7	33.7
Loss on assets sold, including transaction costs	0	-38.3	-0.4
Income (loss) from discontinued operations	-0.2	-10.6	33.3
Provision for income taxes	-0.1	22.4	11.2
Income (loss) from discontinued operations, net	-0.1	-33	22.1
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.3	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	($0.10)	($33.30)	$21.80

Goodwill_and_Asset_Impairments2

Goodwill and Asset Impairments - Changes in Carrying Amount of Goodwill (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Goodwill [Line Items]	'
Beginning Balance	$55.40
Impairment losses, pretax	-15.2
Goodwill written off upon sale, pretax	-40.2
Ending Balance	0
TPS GO [Member]	'
Goodwill [Line Items]	'
Beginning Balance	3.1
Impairment losses, pretax	-3.1
Goodwill written off upon sale, pretax	0
Ending Balance	0
TPS SJI [Member]	'
Goodwill [Line Items]	'
Beginning Balance	52.3
Impairment losses, pretax	-12.1
Goodwill written off upon sale, pretax	-40.2
Ending Balance	$0

Goodwill_and_Asset_Impairments3

Goodwill and Asset Impairments - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill And Long Lived Asset Impairment [Line Items]	'	'	'
Impairment charge	$0	$17.20	$0
TGS [Member]	'	'	'
Goodwill And Long Lived Asset Impairment [Line Items]	'	'	'
Long-lived asset pretax impairment charge	2	'	'
TECO Coal [Member]	'	'	'
Goodwill And Long Lived Asset Impairment [Line Items]	'	'	'
Impairment charge	$0	'	'
Effects of inflation rate	1.00%	1.00%	'

Dispositions_Additional_Inform

Dispositions - Additional Information (Detail) (USD $)	2 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 01, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 27, 2012
Subsidiary or Equity Method Investee [Line Items]	'	'	'	'	'
Proceeds from sale	'	'	'	'	$227.50
Repayment of debt	75	51.6	650.4	153.6	'
Sale resulted after-tax charge associated with foreign tax credits	'	'	22.9	'	'
San Jos And Alborada Power Stations [Member]	'	'	'	'	'
Subsidiary or Equity Method Investee [Line Items]	'	'	'	'	'
Proceeds from sale	'	'	'	'	227.5
TECO Guatemala [Member]	'	'	'	'	'
Subsidiary or Equity Method Investee [Line Items]	'	'	'	'	'
Net proceeds from sale	'	197	'	'	'
Repayment of debt	'	25.3	'	'	'
San Jose Power Station [Member]	'	'	'	'	'
Subsidiary or Equity Method Investee [Line Items]	'	'	'	'	'
Sale after tax book loss	'	28.6	'	'	'
Sale resulted after-tax charge associated with foreign tax credits	'	$22.90	'	'	'

Pending_Acquisition_of_New_Mex1

Pending Acquisition of New Mexico Gas Company - Additional Information (Detail) (USD $)

0 Months Ended

0 Months Ended

6 Months Ended

12 Months Ended

0 Months Ended

25-May-13

Dec. 31, 2013

Dec. 31, 2012

Dec. 17, 2013

Dec. 17, 2013

Jun. 24, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 17, 2013

Dec. 17, 2013

Jun. 24, 2013

Components of Rate Base [Member]

London Interbank Offered Rate (LIBOR) [Member]

Bridge Facility [Member]

Bridge Facility [Member]

Bridge Facility [Member]

Bridge Facility [Member]

Letters of Credit [Member]

New Mexico Gas Company [Member]

New Mexico Gas Company [Member]

Minimum [Member]

Maximum [Member]

London Interbank Offered Rate (LIBOR) [Member]

Bridge Facility [Member]

Loans At Acquisition Date [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Purchase Price

$950,000,000

'

'

'

'

$950,000,000

'

'

'

'

'

'

Senior Secured Notes at NMGC

200,000,000

'

'

'

'

'

'

'

'

'

'

'

Aggregate liability with respect to such indemnification obligations

'

30,000,000

'

'

'

'

'

'

'

'

'

'

Aggregate liability with respect to such indemnification obligations deductible

'

9,250,000

'

'

'

'

'

'

'

'

'

'

Bank credit facility

'

675,000,000

675,000,000

'

'

1,075,000,000

'

'

'

'

125,000,000

125,000,000

Maturity period

'

'

'

'

'

'

'364 days

'

'

'

'

'

Interest rate margin

'

'

'

0.50%

1.00%

'

'

0.25%

2.00%

'

'

'

Increase on variable rate for each period that elapses after acquisition closing

'

'

'

'

'

'

0.25%

'

'

'

'

'

Period after which company is subject to an increase in variable rate

'

'

'

'

'

'

'90 days

'

'

'

'

'

Total capitalization ratio

'

'

'

'

'

'

0.7

'

'

'

'

'

Normal capitalization ratio

'

'

'

'

'

'

0.65

'

'

'

'

'

Credit agreement maturity date

'

'

'

'

'

'

'

'

'

'

17-Dec-18

'

Increase commitment under credit facility

'

'

'

$75,000,000

'

'

'

'

'

$40,000,000

'

'

Quarterly_Data_Schedule_of_Fin

Quarterly Data - Schedule of Financial Data by Quarter (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Data [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$688.40	$765.90	$735.90	$661.10	$688.40	$858.60	$752.50	$697.10	$2,851.30	$2,996.60	$3,209.90
Income from operations	99.6	140.5	119.5	104.1	109.5	183.1	149.1	114.8	463.7	556.5	583.2
Net income from continuing operations	42.1	62.9	51.6	41.2	45.6	90.2	65.6	44.6	197.8	246	250.8
Net income attributable to TECO Energy	$42	$62.80	$51.40	$41.50	$45.10	$44	$73.10	$50.50	$197.70	$212.70	$272.60
EPS - Basic	'	'	'	'	'	'	'	'	'	'	'
From continuing operations	$0.20	$0.29	$0.24	$0.19	$0.21	$0.42	$0.30	$0.21	$0.92	$1.14	$1.17
Attributable to TECO Energy	'	'	'	'	'	'	'	'	$0.92	$0.99	$1.27
EPS - Diluted	'	'	'	'	'	'	'	'	'	'	'
From continuing operations	$0.20	$0.29	$0.24	$0.19	$0.21	$0.42	$0.30	$0.20	$0.92	$1.14	$1.17
Attributable to TECO Energy	'	'	'	'	'	'	'	'	$0.92	$0.99	$1.27
Dividends paid per common share outstanding	$0.22	$0.22	$0.22	$0.22	$0.22	$0.22	$0.22	$0.22	$0.88	$0.88	$0.85
TECO Energy [Member]	'	'	'	'	'	'	'	'	'	'	'
EPS - Basic	'	'	'	'	'	'	'	'	'	'	'
Attributable to TECO Energy	$0.20	$0.29	$0.24	$0.19	$0.21	$0.20	$0.34	$0.24	'	'	'
EPS - Diluted	'	'	'	'	'	'	'	'	'	'	'
Attributable to TECO Energy	$0.20	$0.29	$0.24	$0.19	$0.21	$0.20	$0.34	$0.23	'	'	'

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 17, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Feb. 15, 2014	Feb. 15, 2014	Feb. 15, 2014	Feb. 15, 2014
			Tampa Electric Company [Member]	Tampa Electric Company [Member]	Tampa Electric Company [Member]	1-year Accounts Receivable Facility [Member]	1-year Accounts Receivable Facility [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]
						Tampa Electric Company [Member]	Tampa Electric Company [Member]		Tampa Electric Company [Member]	1-year Accounts Receivable Facility [Member]	1-year Accounts Receivable Facility [Member]
											Tampa Electric Company [Member]
Subsequent Event [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Line of credit facility maximum borrowing capacity	$675,000,000	$675,000,000	$475,000,000	$200,000,000	$475,000,000	$150,000,000	$150,000,000	'	$150,000,000	$150,000,000	$150,000,000
Basis spread on federal funds rate	'	'	'	'	'	'	'	'	0.50%	0.50%	'
Commitment fees, percentage	'	'	'	'	'	'	'	'	0.70%	0.70%	'
Debt instrument maturity date	'	'	'	'	'	'	'	'Feb. 13, 2015	'Feb. 13, 2015	'Feb. 13, 2015	'

Consolidated_Statements_of_Cap2

Consolidated Statements of Capitalization - Capital Stock (Detail) (USD $)	3 Months Ended		12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Common equity, shares authorized	400,000,000	400,000,000	400,000,000	400,000,000
Capital Stock Outstanding December 31, Shares	217,300,000	216,600,000	217,300,000	216,600,000
Cash Dividends Paid Per Share	$0.22	$0.22	$0.88	$0.88
Cash Dividends Paid	'	'	$191.20	$190.40
Tampa Electric Company [Member]	'	'	'	'
Common equity, shares authorized	25,000,000	25,000,000	25,000,000	25,000,000
Current Redemption on Price	'	'	'	'
Capital Stock Outstanding December 31, Shares	10	10	10	10
Capital Stock Outstanding December 31, Amount	2,030.40	1,970.40	2,030.40	1,970.40
Cash Dividends Paid Per Share	'	'	'	'
Cash Dividends Paid	'	'	$222.10	$228.30

Consolidated_Statements_of_Cap3

Consolidated Statements of Capitalization - Capital Stock (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Equity contributions made by TECO Energy	$60	$118
Preferred Stock Par Value [Member]	'	'
Preferred stock - par value	$1	'
Preferred stock, shares authorized	10	'
Preferred stock, shares outstanding	0	'
Tampa Electric Company [Member] | Preferred Stock Par Value [Member]	'	'
Preferred stock - par value	$100	'
Preferred stock, shares authorized	1.5	'
Preferred stock, shares outstanding	0	'
Tampa Electric Company [Member] | Preferred Stock No Par Value [Member]	'	'
Preferred stock, no par value	'	'
Preferred stock, shares authorized	2.5	'
Preferred stock, shares outstanding	0	'
Tampa Electric Company [Member] | Preference Stock No Par Value [Member]	'	'
Preferred stock, no par value	'	'
Preferred stock, shares authorized	2.5	'
Preferred stock, shares outstanding	0	'

Consolidated_Statements_of_Cap4

Consolidated Statements of Capitalization - Long-Term Debt (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Long-term debt, total	$2,923.80	$2,975.40
Long-term debt, carrying amount	2,921.10	2,972.70
Unamortized debt discount, net	-2.7	-2.7
Less amount due within one year	83.3	0
Total long-term debt	2,837.80	2,972.70
Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	1,880.80	1,932.60
Long-term debt, carrying amount	1,882.60	1,934.20
Total long-term debt	1,797.50	1,932.60
PGS [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	231.7	'
PGS [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	231.7	231.7
6.1% Notes [Member] | PGS [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	50	50
5.4% Notes [Member] | PGS [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2021	'
Long-term debt, total	46.7	46.7
2.6% Notes [Member] | PGS [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2022	'
Long-term debt, total	25	25
6.15% Notes [Member] | PGS [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2037	'
Long-term debt, total	60	60
4.1% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2042	'
4.1% Notes [Member] | PGS [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2042	'
Long-term debt, total	50	50
Tampa Electric Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	1,650.90	1,702.50
Less amount due within one year	83.3	0
Total long-term debt	1,797.50	1,932.60
Tampa Electric Company [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	1,650.90	1,702.50
Unamortized debt discount, net	-1.8	-1.6
Less amount due within one year	83.3	0
Long-term debt, fair value	2,042	2,271.90
Tampa Electric Company [Member] | Long-Term Debt [Member] | Carrying Amount [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, carrying amount	1,880.80	1,932.60
Tampa Electric Company [Member] | Variable rate bonds repurchased in 2008 Due To 2020 [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2020	'
Long-term debt, total	0	0
Tampa Electric Company [Member] | 5.65% Refunding bonds [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	54.2	54.2
Tampa Electric Company [Member] | 5.65% Refunding bonds [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	54.2	54.2
Tampa Electric Company [Member] | 5.15% Refunding bonds [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2025	'
Long-term debt, total	0	51.6
Tampa Electric Company [Member] | 5.15% Refunding bonds [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2025	'
Long-term debt, total	0	51.6
Tampa Electric Company [Member] | 1.5% term rate bonds repurchased in 2011 [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2030	'
Long-term debt, total	0	0
Tampa Electric Company [Member] | 1.5% term rate bonds repurchased in 2011 [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2030	'
Long-term debt, total	0	0
Tampa Electric Company [Member] | 5.0% Refunding bonds [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2034	'
Long-term debt, total	0	0
Tampa Electric Company [Member] | 5.0% Refunding bonds [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2034	'
Long-term debt, total	0	0
Tampa Electric Company [Member] | 6.25% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Maturity range start	'2014	'
Long-term debt, total	250	250
Tampa Electric Company [Member] | 6.25% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2016	'
Maturity range start	'2014	'
Long-term debt, total	250	250
Tampa Electric Company [Member] | 6.1% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	200	200
Tampa Electric Company [Member] | 6.1% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2018	'
Long-term debt, total	200	200
Tampa Electric Company [Member] | 5.4% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2021	'
Long-term debt, total	231.7	231.7
Tampa Electric Company [Member] | 5.4% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2021	'
Long-term debt, total	231.7	231.7
Tampa Electric Company [Member] | 2.6% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2022	'
Long-term debt, total	225	225
Tampa Electric Company [Member] | 2.6% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2022	'
Long-term debt, total	225	225
Tampa Electric Company [Member] | 6.55% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2036	'
Long-term debt, total	250	250
Tampa Electric Company [Member] | 6.55% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2036	'
Long-term debt, total	250	250
Tampa Electric Company [Member] | 6.15% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2037	'
Long-term debt, total	190	190
Tampa Electric Company [Member] | 6.15% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2037	'
Long-term debt, total	190	190
Tampa Electric Company [Member] | 4.1% Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt, total	250	250
Tampa Electric Company [Member] | 4.1% Notes [Member] | Long-Term Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Due	'2042	'
Long-term debt, total	$250	$250

Consolidated_Statements_of_Cap5

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) (Detail) (USD $)

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2008

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

PGS [Member]

PGS [Member]

PGS [Member]

PGS [Member]

PGS [Member]

Tampa Electric Company [Member]

Tampa Electric Company [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

Tampa Electric [Member]

6.1% Notes [Member]

5.4% Notes [Member]

2.6% Notes [Member]

6.15% Notes [Member]

4.1% Notes [Member]

Variable rate bonds repurchased in 2008 Due To 2020 [Member]

Variable Rate Bonds [Member]

5.65% Refunding bonds [Member]

5.15% Refunding bonds [Member]

1.5% term rate bonds repurchased in 2011 [Member]

5.0% Refunding bonds [Member]

6.25% Notes [Member]

6.1% Notes [Member]

5.4% Notes [Member]

2.6% Notes [Member]

6.55% Notes [Member]

6.15% Notes [Member]

4.1% Notes [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Effective interest rate

7.00%

5.40%

2.70%

6.20%

4.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

Stated interest rate

6.10%

5.40%

2.60%

6.15%

4.10%

'

'

5.65%

5.15%

1.50%

5.00%

6.25%

6.10%

5.40%

2.60%

6.55%

6.15%

4.10%

Variable rate bonds, par amounts

'

'

'

'

'

$20

$86

'

'

'

'

'

'

'

'

'

'

'

Consolidated_Statements_of_Cap6

Consolidated Statements of Capitalization - Long-term Debt Maturities (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'
Total long-term debt maturities	$2,923.80
Tampa Electric Company [Member]	'
Debt Instrument [Line Items]	'
2014	83.3
2015	83.3
2016	83.4
2017	0
2018	254.2
Thereafter	1,146.70
Total long-term debt maturities	1,650.90
Long Term Debt Maturities [Member]	'
Debt Instrument [Line Items]	'
2014	83.3
2015	83.3
2016	83.4
2017	0
2018	304.2
Thereafter	1,328.40
Total long-term debt maturities	1,882.60
PGS [Member]	'
Debt Instrument [Line Items]	'
2014	0
2015	0
2016	0
2017	0
2018	50
Thereafter	181.7
Total long-term debt maturities	$231.70

Recovered_Sheet7

Employee Postretirement Benefits - Schedule of Amount Recognized in Balance Sheet (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	$139.60	$216.50
Accrued benefit costs and other current liabilities	-3.3	-5.3
Deferred credits and other liabilities	-69.7	-180.6
Net amount recognized at end of year	99.7	83.7
Pension Benefits [Member] | Tampa Electric Company [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	139.6	216.5
Accrued benefit costs and other current liabilities	-0.9	-0.9
Deferred credits and other liabilities	-50.1	-139.8
Net amount recognized at end of year	88.6	75.8
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	-13.3	-13.1
Deferred credits and other liabilities	-194.8	-217.2
Net amount recognized at end of year	-189.1	-188.6
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	-10.8	-10.6
Deferred credits and other liabilities	-158.3	-174.2
Net amount recognized at end of year	($125.90)	($125.20)

Schedule_II_Valuation_and_Qual1

Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation and Qualifying Accounts Disclosure [Line Items]	'	'	'
Balance at Beginning of Period	$4.20	$2.60	$4.50
Charged to Income	3.3	4.8	3.8
Other Charges	0	0	0
Payments & Deductions	2.8	3.2	5.7
Balance at End of Period	4.7	4.2	2.6
Tampa Electric Company [Member]	'	'	'
Valuation and Qualifying Accounts Disclosure [Line Items]	'	'	'
Balance at Beginning of Period	1.5	1.3	3.2
Charged to Income	3.3	3.4	3.8
Other Charges	0	0	0
Payments & Deductions	2.8	3.2	5.7
Balance at End of Period	$2	$1.50	$1.30