Tampa Electric 10-Q8 Nov 162016 Q3 Quarterly reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2016	Nov. 04, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	350,563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	96,271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 24.4	$ 23.8
Receivables, less allowance for uncollectibles	268.2	280.7
Inventories, at average cost
Regulatory assets	21.8	44.8
Prepayments and other current assets	24	30.8
Total current assets	507.3	570.3
Property, plant and equipment
Construction work in progress	916.8	794.7
Other property	16.8	15.9
Property, plant and equipment, at original costs	10,624.1	10,194.7
Accumulated depreciation	(2,862.2)	(2,712.9)
Total property, plant and equipment, net	7,761.9	7,481.8
Other assets
Regulatory assets	458.7	395.2
Goodwill	408.4	408.4
Deferred charges and other assets	87.4	77.8
Total other assets	954.5	881.4
Total assets	9,223.7	8,933.5
Current liabilities
Long-term debt due within one year	0	333.3
Notes payable	610.5	247
Accounts payable	264	255.4
Customer deposits	160.6	182.1
Regulatory liabilities	148.2	84.8
Derivative liabilities	1.6	24.1
Interest accrued	53.1	36.2
Taxes accrued	65	13.2
Other	44.5	22.6
Total current liabilities	1,347.5	1,198.7
Other liabilities
Deferred income taxes	650.1	570.7
Investment tax credits	10.2	10.5
Regulatory liabilities	718.8	715.8
Deferred credits and other liabilities	412.6	389.6
Long-term debt, less amount due within one year	3,490.3	3,489.2
Total other liabilities	5,282	5,175.8
Commitments and contingencies
Capital
Common equity	0	235.3
Additional paid in capital	2,154.7	1,894.5
Retained earnings	457.1	441.4
Accumulated other comprehensive loss	(17.6)	(12.2)
Total capital	2,594.2	2,559
Long-term debt	3,490.3	3,489.2
Total liabilities and capital	9,223.7	8,933.5
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	15.4	9.1
Receivables, less allowance for uncollectibles	254.9	230.2
Inventories, at average cost
Taxes receivable from affiliate	0	61.3
Regulatory assets	20.6	44.3
Prepayments and other current assets	16.3	21.5
Total current assets	468.1	545.1
Property, plant and equipment
Construction work in progress	875.2	771.1
Utility plant in service, at original costs	9,815.4	9,440
Accumulated depreciation	(2,808.3)	(2,676.8)
Utility plant in service, net	7,007.1	6,763.2
Other property	10.5	9.7
Total property, plant and equipment, net	7,017.6	6,772.9
Other assets
Regulatory assets	438.2	373.8
Deferred charges and other assets	468.1	390.6
Other	29.9	16.8
Total assets	7,953.8	7,708.6
Current liabilities
Long-term debt due within one year	0	83.3
Notes payable	49	61
Accounts payable	222	221.6
Customer deposits	155.2	176.3
Regulatory liabilities	140.4	83.2
Derivative liabilities	1.4	24.1
Interest accrued	40.1	16.9
Taxes accrued	74.5	13.2
Other	10.3	10.2
Total current liabilities	692.9	689.8
Other liabilities
Deferred income taxes	1,388.2	1,308.8
Investment tax credits	10.2	10.5
Regulatory liabilities	597	603.5
Deferred credits and other liabilities	339.3	318.8
Long-term debt, less amount due within one year	2,162.6	2,161.7
Total deferred credits	2,334.7	2,241.6
Commitments and contingencies
Capital
Common equity	2,395.4	2,305.4
Retained earnings	371.2	313.7
Accumulated other comprehensive loss	(3)	(3.6)
Total capital	2,763.6	2,615.5
Long-term debt	2,162.6	2,161.7
Total capitalization	4,926.2	4,777.2
Total liabilities and capital	7,953.8	7,708.6
Fuel [Member]
Inventories, at average cost
Utility inventories	85.2	113.4
Fuel [Member] \| Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	80.7	105.6
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	83.7	76.8
Materials and Supplies [Member] \| Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	80.2	73.1
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,473.9	7,270.3
Electric [Member] \| Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,473.9	7,270.3
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	2,216.6	2,113.8
Gas [Member] \| Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,466.3	$ 1,398.6

Consolidated Condensed Balance3

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Allowance for uncollectibles	$ 2.9	$ 2.1
Common equity, shares authorized	10,000,000	400,000,000
Common equity, par value	$ 0.01	$ 1
Common equity, shares outstanding	1,000	235,300,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 2.5	$ 1.5

Consolidated Condensed Statemen

Consolidated Condensed Statements of Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Regulated electric	$ 585.2	$ 559.3	$ 1,506.6	$ 1,540.8
Regulated gas	138.6	131.5	522.9	518.1
Unregulated	2.9	3	9	8.5
Total revenues	726.7	693.8	2,038.5	2,067.4
Expenses
Fuel	173.5	176.6	426.1	492.5
Purchased power	38.3	23.8	80.5	60.5
Cost of natural gas sold	53.2	42	200.8	194.1
Other	153.6	150.1	452.2	451.9
Merger transaction-related costs	37.9	15.4	109.4	15.4
Depreciation and amortization	92	87.8	272	260.3
Taxes, other than income	56.3	51.5	160.8	156.6
Total expenses	604.8	547.2	1,701.8	1,631.3
Income from operations	121.9	146.6	336.7	436.1
Other income
Allowance for other funds used during construction	6.5	4.7	18.1	12.2
Other income, net	2.1	1.4	4.6	4.4
Total other income	8.6	6.1	22.7	16.6
Interest charges
Interest expense	47.1	48.4	142.7	146.4
Allowance for borrowed funds used during construction	(3.2)	(2.3)	(9.1)	(6)
Total interest charges	43.9	46.1	133.6	140.4
Income from continuing operations before provision for income taxes	86.6	106.6	225.8	312.3
Provision for income taxes	17.2	41.7	77.2	122.1
Net income from continuing operations	69.4	64.9	148.6	190.2
Discontinued operations
Loss from discontinued operations	(0.2)	(17.8)	(0.4)	(105.5)
Benefit for income taxes	0.2	6.1	0.3	38.3
Loss from discontinued operations, net	0	(11.7)	(0.1)	(67.2)
Net income	$ 69.4	$ 53.2	$ 148.5	$ 123

Consolidated Condensed Stateme5

Consolidated Condensed Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net income		$ 69.4		$ 53.2		$ 148.5		$ 123
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2		0.2		0.6		3.3
Amortization of unrecognized benefit costs and other	[1]	0.5		0.2		0.8		1.8
Recognized cost due to curtailment		0	[2]	0		0.1	[2]	0
Change in benefit obligation due to remeasurement/ valuation		(6.9)		(5.7)		(6.9)		(5.7)
Recognized cost due to settlement		0		7.7	[3]	0		7.7	[3]
Other comprehensive income (loss), net of tax		(6.2)		2.4		(5.4)		7.1
Comprehensive income		$ 63.2		$ 55.6		$ 143.1		$ 130.1

[1]	Related to postretirement benefits. See Note 5 for additional information.
[2]	Related to the estimated curtailment loss for the SERP. See Note 5 for additional information.
[3]	Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 15 for additional information.

Consolidated Condensed Stateme6

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities
Net income	$ 148.5	$ 123
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	272	261.5
Depreciation and amortization	272	260.3
Deferred income taxes and investment tax credits	76.5	84.6
Allowance for other funds used during construction	(18.1)	(12.2)
Non-cash stock compensation	6.4	10.1
Loss on disposals of business/assets, pretax	(0.3)	10
Deferred recovery clauses	54.5	13.1
Asset impairment, pretax	0	78.6
Receivables, less allowance for uncollectibles	12.5	46.1
Inventories	21.3	(45.7)
Prepayments and other current assets	6.8	(14.2)
Taxes accrued	54	31.6
Interest accrued	16.9	14.7
Accounts payable	27.7	(85.7)
Other	(27.6)	(34.6)
Cash flows from operating activities	651.1	480.9
Cash flows from investing activities
Capital expenditures	(573.3)	(511)
Other investing activities	8.5	(0.2)
Cash flows used in investing activities	(564.8)	(511.2)
Cash flows from financing activities
Dividends and dividend equivalents	(135.4)	(158.8)
Proceeds from the sale of common stock and equity contributions	26.2	6.4
Proceeds from long-term debt issuance	0	499.7
Repayment of long-term debt	(333.3)	(274.5)
Net decrease in short-term debt (maturities of 90 days or less)	(36.5)	(11)
Proceeds from other short-term debt (maturities over 90 days)	400	0
Other financing activities	(6.7)	(1.5)
Cash flows from (used in) financing activities	(85.7)	60.3
Net increase in cash and cash equivalents	0.6	30
Cash and cash equivalents at beginning of the period	23.8	25.4
Cash and cash equivalents at end of the period	24.4	55.4
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	(20.6)	(8.1)
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	239.6	226.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	245.1	233.8
Deferred income taxes and investment tax credits	69.8	52.6
Allowance for other funds used during construction	(17.8)	(12.1)
Deferred recovery clauses	54.3	13.7
Receivables, less allowance for uncollectibles	(24.7)	(31.4)
Inventories	17.8	(44.4)
Prepayments and other current assets	6.4	(7.9)
Taxes accrued	122.6	93.6
Interest accrued	23.2	24.5
Accounts payable	18.6	(39.8)
Other	(52.3)	(34.4)
Cash flows from operating activities	702.6	474.6
Cash flows from investing activities
Capital expenditures	(517.6)	(473.8)
Net proceeds from sale of assets	8.7	0
Cash flows used in investing activities	(508.9)	(473.8)
Cash flows from financing activities
Dividends and dividend equivalents	(182.1)	(175.9)
Common stock	90	88
Proceeds from long-term debt issuance	0	251.2
Repayment of long-term debt	(83.3)	(83.3)
Net decrease in short-term debt (maturities of 90 days or less)	(12)	(58)
Cash flows from (used in) financing activities	(187.4)	22
Net increase in cash and cash equivalents	6.3	22.8
Cash and cash equivalents at beginning of the period	9.1	10.4
Cash and cash equivalents at end of the period	15.4	33.2
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (19.6)	$ (10.1)

Consolidated Condensed Stateme7

Consolidated Condensed Statements of Capital (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Balance, Dec. 31, 2015		$ 2,559
Net income	$ 69.4	148.5
Other comprehensive loss, after tax	(6.2)	(5.4)
Common stock issued		(1.6)
Impact of Merger		0
Dividends and dividend equivalents		(135.4)
Stock compensation expense		6.4
Restricted stock—dividends		(1.6)
Cumulative effect of change in accounting		2.6
Equity contribution		22.1
Other		(0.4)
Balance, Sept. 30, 2016	2,594.2	2,594.2
Common Stock [Member]
Balance, Dec. 31, 2015		$ 235.3
Balance, Dec. 31, 2015, shares		235.3
Common stock issued		$ 0.2
Common stock issued, shares		0.2
Impact of Merger		$ (235.5)
Impact of Merger, shares		(235.3)
Balance, Sept. 30, 2016	$ 0	$ 0
Balance, Sept. 30, 2016, shares	0	0
Additional Paid-in Capital [Member]
Balance, Dec. 31, 2015		$ 1,894.5
Common stock issued		(1.8)
Impact of Merger		235.5
Stock compensation expense		6.4
Restricted stock—dividends		(1.6)
Equity contribution		22.1
Other		(0.4)
Balance, Sept. 30, 2016	$ 2,154.7	2,154.7
Retained Earnings [Member]
Balance, Dec. 31, 2015		441.4
Net income		148.5
Dividends and dividend equivalents		(135.4)
Cumulative effect of change in accounting		2.6
Balance, Sept. 30, 2016	457.1	457.1
Accumulated Other Comprehensive Income (Loss) [Member]
Balance, Dec. 31, 2015		(12.2)
Other comprehensive loss, after tax		(5.4)
Balance, Sept. 30, 2016	$ (17.6)	$ (17.6)

Consolidated Condensed Stateme8

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Total revenues	$ 726.7	$ 693.8	$ 2,038.5	$ 2,067.4
Expenses
Fuel	173.5	176.6	426.1	492.5
Purchased power	38.3	23.8	80.5	60.5
Cost of natural gas sold	53.2	42	200.8	194.1
Other	153.6	150.1	452.2	451.9
Depreciation and amortization	92	87.8	272	260.3
Taxes, other than income	56.3	51.5	160.8	156.6
Total expenses	604.8	547.2	1,701.8	1,631.3
Income from operations	121.9	146.6	336.7	436.1
Other income
Allowance for other funds used during construction	6.5	4.7	18.1	12.2
Other income, net	2.1	1.4	4.6	4.4
Total other income	8.6	6.1	22.7	16.6
Interest charges
Interest expense	47.1	48.4	142.7	146.4
Allowance for borrowed funds used during construction	(3.2)	(2.3)	(9.1)	(6)
Total interest charges	43.9	46.1	133.6	140.4
Income before provision for income taxes	86.6	106.6	225.8	312.3
Provision for income taxes	17.2	41.7	77.2	122.1
Net income	69.4	53.2	148.5	123
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.2	0.6	3.3
Other comprehensive income (loss), net of tax	(6.2)	2.4	(5.4)	7.1
Comprehensive income	63.2	55.6	143.1	130.1
Tampa Electric Company [Member]
Revenues
Electric	586	560.1	1,509	1,542.9
Gas	103.1	88.1	329.9	302
Total revenues	689.1	648.2	1,838.9	1,844.9
Expenses
Fuel	173.5	176.6	426.1	492.5
Purchased power	38.3	23.8	80.5	60.5
Cost of natural gas sold	40.4	28.5	126.4	101.9
Other	134.6	128.7	388.2	384.8
Depreciation and amortization	82.8	79	245.1	233.8
Taxes, other than income	52.6	47.8	148.6	144.9
Total expenses	522.2	484.4	1,414.9	1,418.4
Income from operations	166.9	163.8	424	426.5
Other income
Allowance for other funds used during construction	6.2	4.6	17.8	12.1
Other income, net	2.1	1.2	4.3	3.6
Total other income	8.3	5.8	22.1	15.7
Interest charges
Interest on long-term debt	27.7	29	84.5	84.5
Other interest	1.5	1
Interest expense			3.9	3.3
Allowance for borrowed funds used during construction	(3.1)	(2.2)	(8.6)	(5.8)
Total interest charges	26.1	27.8	79.8	82
Income before provision for income taxes	149.1	141.8	366.3	360.2
Provision for income taxes	48.5	53.5	126.7	133.8
Net income	100.6	88.3	239.6	226.4
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.2	0.6	3.3
Other comprehensive income (loss), net of tax	0.2	0.2	0.6	3.3
Comprehensive income	$ 100.8	$ 88.5	$ 240.2	$ 229.7

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
Summary of Significant Accounting Policies	Sep. 30, 2016
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies See TECO Energy, Inc.’s 2015 Annual Report on Form 10-K for a complete discussion of the company’s accounting policies. The significant accounting policies for all utility and diversified operations include: Principles of Consolidation and Basis of Presentation Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries. See Note 14 Revenues As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $71.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Accounting for Franchise Fees and Gross Receipt Taxes Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, compared to $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.
Tampa Electric Company [Member]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies See TEC’s 2015 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include: Principles of Consolidation and Basis of Presentation TEC is a wholly owned subsidiary of TECO Energy. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS. For the periods presented, no VIEs have been consolidated (see Note 13 Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. Note 14 Revenues As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $63.7 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Accounting for Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, and $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
New Accounting Pronouncements	Sep. 30, 2016
New Accounting Pronouncements	2. New Accounting Pronouncements Change in Accounting Policy The new U.S. GAAP accounting policies that are applicable to and were adopted by the company are described as follows: Interest – Imputation of Interest In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest Interest: Imputation of Interest Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. Compensation – Stock Compensation In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation • Income tax consequences – The company will no longer recognize excess tax benefits and certain tax deficiencies in additional paid in capital. Instead, the company will recognize all excess tax benefits and tax deficiencies as income tax expense or benefit on the income statement. In addition, the guidance eliminates the requirement that excess tax benefits be realized before the company can recognize them. The company recorded a $2.6 million cumulative adjustment to retained earnings as of Jan. 1, 2016 for excess tax benefits related to prior periods. • Accounting for forfeitures – The company’s policy is to estimate the number of awards expected to be forfeited, which is consistent with prior periods. • Classification of awards - The company had no share-based payments classified as liability awards as of Sept. 30, 2016 or Dec. 31, 2015. • Presentation on the statement of cash flows – Excess tax benefits are required to be presented as an operating activity on the statement of cash flows rather than as a financing activity. The change may be applied retrospectively or prospectively. The company elected to apply it prospectively, and prior periods were not retrospectively adjusted. Additionally, employee taxes paid by an employer to a tax authority when shares are withheld for tax-withholding purposes are required to be presented as a financing activity on a retrospective basis for all periods presented. Therefore, the company reclassified $1.5 million from operating activities to financing activities for the nine months ended Sept. 30, 2015. Future Accounting Pronouncements The company considers the applicability and impact of all ASUs issued by FASB. The following updates have been issued by FASB but have not yet been adopted by TECO Energy. Any ASUs not included below were assessed and determined to be either not applicable to the company or are not expected to have a material impact on the consolidated financial statements. Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02, Leases. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows
Tampa Electric Company [Member]
New Accounting Pronouncements	2. New Accounting Pronouncements Change in Accounting Policy The new U.S. GAAP accounting policies that are applicable to and were adopted by TEC are described as follows: Interest – Imputation of Interest In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest Interest: Imputation of Interest Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. Future Accounting Pronouncements TEC considers the applicability and impact of all ASUs issued by FASB. The following updates have been issued by FASB but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or are not expected to have a material impact on the consolidated financial statements. Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02, Leases. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

Regulatory

Regulatory	9 Months Ended
Regulatory	Sep. 30, 2016
Regulatory	3. Regulatory Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. Regulatory Assets and Liabilities Tampa Electric, PGS and NMGC 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; 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; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2016 Dec. 31, 2015 Regulatory assets: Regulatory tax asset (1) $ 83.4 $ 74.7 Cost-recovery clauses - deferred balances (2) 4.5 5.5 Cost-recovery clauses - offsets to derivative liabilities (2) 2.1 26.5 Environmental remediation (3) 54.8 54.0 Postretirement benefits (4) 296.4 240.6 Deferred bond refinancing costs (5) 7.1 6.5 Debt basis adjustment (6) 14.9 17.5 Competitive rate adjustment (2) 2.5 2.6 Other 14.8 12.1 Total regulatory assets 480.5 440.0 Less: Current portion 21.8 44.8 Long-term regulatory assets $ 458.7 $ 395.2 Regulatory liabilities: Regulatory tax liability $ 7.2 $ 7.9 Cost-recovery clauses (2) 111.5 55.9 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (7) 670.6 679.9 Bill reduction credit (8) 8.0 0.3 Other 13.6 0.5 Total regulatory liabilities 867.0 800.6 Less: Current portion 148.2 84.8 Long-term regulatory liabilities $ 718.8 $ 715.8 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument. (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (8) See Note 14
Tampa Electric Company [Member]
Regulatory	3. Regulatory Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. Regulatory Assets and Liabilities 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; 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; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2016 Dec. 31, 2015 Regulatory assets: Regulatory tax asset (1) $ 83.1 $ 74.6 Cost-recovery clauses - deferred balances (2) 4.4 5.2 Cost-recovery clauses - offsets to derivative liabilities (2) 1.5 26.2 Environmental remediation (3) 54.8 54.0 Postretirement benefits (4) 296.5 238.3 Deferred bond refinancing costs (5) 5.9 6.5 Competitive rate adjustment (2) 2.5 2.6 Other 10.1 10.7 Total regulatory assets 458.8 418.1 Less: Current portion 20.6 44.3 Long-term regulatory assets $ 438.2 $ 373.8 Regulatory liabilities: Regulatory tax liability $ 5.3 $ 5.7 Cost-recovery clauses (2) 107.8 54.2 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (6) 554.8 570.0 Other 13.4 0.7 Total regulatory liabilities 737.4 686.7 Less: Current portion 140.4 83.2 Long-term regulatory liabilities $ 597.0 $ 603.5 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

Income Taxes

Income Taxes	9 Months Ended
Income Taxes	Sep. 30, 2016
Income Taxes	4. Income Taxes The effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 19.86% and 39.12%, respectively. The effective tax rate decreased to 34.19% for the nine months ended Sept. 30, 2016 from 39.10% for the same period in 2015. The decrease in the three-month effective tax rate of 19.26% in 2016 versus the same period in 2015 is primarily due to tax benefits recorded in the third quarter of 2016 for federal R&D credits, lower non-deductible Merger transaction costs and other permanent book-to-tax differences. The effective tax rate for year-to-date 2016 differed from the U.S. statutory rate of 35% primarily due to the effects of federal R&D credits and the tax benefit related to long-term incentive compensation offset by non-deductible Merger transaction costs (see Notes 2 and 14 Effective July 1, 2016 and due to the Merger with Emera, TECO Energy and its subsidiaries are included in a consolidated U.S federal income tax return with EUSHI and its subsidiaries. TECO Energy’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TECO Energy’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution. The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2013 and forward. Years 2015 and the short tax year ending June 30, 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, the company is only eligible to participate in the CAP through its short tax year ending June 30, 2016. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. 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 and foreign jurisdictions include 2005 and forward. Accounting for Uncertainty in Income Taxes Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes. As of Sept. 30, 2016 and Dec. 31, 2015, TECO Energy’s uncertain tax positions were $7.7 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for net operating losses and tax credit carryforwards. The increase was primarily due to an uncertain tax position related to federal R&D tax credits. TECO Energy believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s federal income tax return for the short tax year ending June 30, 2016. As of Sept. 30, 2016, if recognized, $7.7 million of the unrecognized tax benefits would reduce TECO Energy’s effective tax rate.
Tampa Electric Company [Member]
Income Taxes	4. Income Taxes Effective July 1, 2016 and due to the Merger with Emera, TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution. Taxes accrued to affiliates was $14.2 million as of Sept. 30 2016. TEC’s effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 32.53% and 37.73%, respectively. The effective tax rates for the nine months ended Sept. 30, 2016 and 2015 were 34.59% and 37.15%, respectively. The decrease in the three-month effective tax rate of 5.2% in 2016 versus the same period in 2015 is primarily due to a tax benefit recorded in the third quarter of 2016 for federal R&D credits. TEC’s effective tax rates for the nine months ended Sept. 30, 2016 and 2015 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity and federal R&D credits. The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2013 and forward. Years 2015 and the short tax year ending June 30, 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only able to participate in the CAP through its short tax year ending June 30, 2016. 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 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being Accounting for Uncertainty in Income Taxes Authoritative guidance related to accounting for uncertainty in income taxes require an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes. As of Sept. 30, 2016 and Dec. 31, 2015, TEC’s uncertain tax positions were $6.5 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. The increase was due to an uncertain tax position related to federal R&D tax credits. TEC believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. As of Sept. 30, 2016, if recognized, $6.5 million of the unrecognized tax benefits would reduce TEC’s effective tax rate.

Employee Postretirement Benefit

Employee Postretirement Benefits	9 Months Ended
Employee Postretirement Benefits	Sep. 30, 2016
Employee Postretirement Benefits	5. Employee Postretirement Benefits Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP. Pension Expense (millions) Pension Benefits Other Postretirement Benefits Three months ended Sept. 30, 2016 2015 2016 2015 Components of net periodic benefit expense Service cost $ 4.9 $ 6.7 $ 0.5 $ 0.6 Interest cost 7.2 6.5 2.0 2.0 Expected return on assets (11.5 ) (9.1 ) (0.3 ) (0.3 ) Amortization of: Prior service (benefit) cost 0.0 (0.1 ) (0.6 ) (0.6 ) Actuarial loss 4.8 3.2 0.1 0.0 Regulatory asset 0.0 0.0 0.3 0.3 Curtailment cost 0.0 0.0 0.0 0.0 Settlement cost 0.0 0.0 0.0 0.0 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 5.4 $ 7.2 $ 2.0 $ 2.0 Nine months ended Sept. 30, Components of net periodic benefit expense Service cost $ 13.9 $ 17.6 $ 1.4 $ 1.7 Interest cost 23.6 22.6 6.4 6.1 Expected return on assets (34.2 ) (32.4 ) (0.9 ) (0.8 ) Amortization of: Prior service (benefit) cost 0.2 (0.2 ) (1.9 ) (1.8 ) Actuarial loss 11.7 11.4 0.1 0.0 Regulatory asset 0.0 0.0 0.8 0.8 Curtailment cost 1.3 0.0 0.0 0.0 Settlement cost 0.6 0.0 0.0 0.0 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 17.1 $ 19.0 $ 5.9 $ 6.0 For the Jan. 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the Florida-based plan and 4.687% for the NMGC plan. As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%. As a result of the remeasurement, TECO Energy’s net periodic benefit expense increased by $0.6 million for pension benefits and zero for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TECO Energy’s liability for pension benefits increased by $61.7 million and $17.6 million for other postretirement benefits. The associated regulatory asset increased $54.0 million for pension benefits and $14.1 million for other postretirement benefits. Accumulated other comprehensive income decreased $7.7 million for pension benefits and $3.5 million for other postretirement benefits. TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan for the nine months ended Sept. 30, 2016 and 2015, respectively. Additionally, NMGC made contributions of $2.7 million to its other postretirement benefits plan for the nine months ended Sept. 30, 2016 and 2015. For the three and nine months ended Sept. 30, 2016, TECO Energy and its subsidiaries reclassified $0.8 million and $1.8 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $0.2 million and $2.4 million for the three and nine months ended Sept. 30, 2015, respectively. In addition, during the three and nine months ended Sept. 30, 2016, the regulated companies reclassified $3.8 million and $9.1 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $2.6 million and $7.8 million for the three and nine months ended Sept. 30, 2015, respectively. The settlement cost recognized relates to the settlement of the SERP liability for the TECO Coal participants. An estimated curtailment loss for the SERP of $1.3 million was recognized in the second quarter of 2016 as a result of retirements expected in the third quarter of 2016 as a result of the Merger, which expected retirements occurred in the third quarter of 2016. The company’s postretirement benefit plans were not explicitly impacted by the Merger. However, TECO Energy expects to recognize a settlement charge related to the SERP of approximately $8.0 million in the first quarter of 2017 due to retirements that have occurred as a result of the Merger.
Tampa Electric Company [Member]
Employee Postretirement Benefits	5. Employee Postretirement Benefits TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5 Employee Postretirement Benefits TECO Energy Notes to Consolidated Condensed Financial Statements For the Jan. 1, 2016 measurement, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.667%. As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%. As a result of the remeasurement, TEC’s net periodic benefit expense increased by $0.8 million for pension benefits and $0.3 million for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TEC’s liability and associated regulatory asset for pension benefits increased $53.3 million and $12.4 million for other postretirement benefits. TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan in the nine months ended Sept. 30, 2016 and 2015, respectively. TEC’s portion of the contributions was $30.9 million and $43.9 million, respectively. Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2016, TEC reclassified $2.8 million and $7.6 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.3 million and $7.0 million for the three and nine months ended Sept. 30, 2015, respectively.

Short-Term Debt

Short-Term Debt	9 Months Ended
Short-Term Debt	Sep. 30, 2016
Short-Term Debt	6. Short-Term Debt Details of the credit facilities and related borrowings are presented in the following table: Credit Facilities Sept. 30, 2016 Dec. 31, 2015 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 0.0 $ 0.5 3-year accounts receivable facility (3) 150.0 49.0 0.0 150.0 61.0 0.0 TECO Energy/TECO Finance: 5-year facility (2)(4) 300.0 150.0 0.0 300.0 163.0 0.0 1-year term facility (4)(5) 400.0 400.0 0.0 0.0 0.0 0.0 New Mexico Gas Company: 5-year facility (2) 125.0 11.5 1.4 125.0 23.0 1.7 Total $ 1,300.0 $ 610.5 $ 1.9 $ 900.0 $ 247.0 $ 2.2 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) This 3-year facility matures Mar. 23, 2018. (4) TECO Finance is the borrower and TECO Energy is the guarantor of this facility. (5) This 1-year facility matures Mar. 14, 2017. At Sept. 30, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sept. 30, 2016 and Dec. 31, 2015 was 1.71% and 1.29%, respectively. TECO Energy/TECO Finance Credit Facility On Mar. 14, 2016, TECO Finance entered into a one-year, $400 million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and (iii) provides for interest to accrue at variable rates based on
Tampa Electric Company [Member]
Short-Term Debt	6. Short-Term Debt Details of the credit facilities and related borrowings are presented in the following table: Credit Facilities Sept. 30, 2016 Dec. 31, 2015 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 0.0 $ 0.5 3-year accounts receivable facility (3) 150.0 49.0 0.0 150.0 61.0 0.0 Total $ 475.0 $ 49.0 $ 0.5 $ 475.0 $ 61.0 $ 0.5 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) This 3-year facility matures Mar. 23, 2018. At Sept. 30, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sept. 30, 2016 and Dec. 31, 2015 was 1.32% and 0.89%, respectively.

Long-Term Debt

Long-Term Debt	9 Months Ended
Long-Term Debt	Sep. 30, 2016
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At Sept. 30, 2016, total long-term debt had a carrying amount of $3,490.3 million and an estimated fair market value of $3,911.2 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 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 or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.3 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 measurements (see Note 11 Purchase in Lieu of Redemption of Revenue Refunding Bonds On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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 Mar. 19, 2008 to Mar. 15, 2012. On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. 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. As of Sept. 30, 2016, $232.6 million of bonds purchased in lieu of redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.
Tampa Electric Company [Member]
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At Sept. 30, 2016, TEC’s total long-term debt had a carrying amount of $2,162.6 million and an estimated fair market value of $2,505.6 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,245.0 million and an estimated fair market value of $2,433.3 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.3 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 measurements Note 11 Purchase in Lieu of Redemption of Revenue Refunding Bonds On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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 Mar. 19, 2008 to Mar. 15, 2012. On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. 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. As of Sept. 30, 2016, $232.6 million of bonds purchased in lieu of redemption, including the series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
Commitments and Contingencies	Sep. 30, 2016
Commitments and Contingencies	8. 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. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. Peoples Gas 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. 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, a suit was 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 and a PGS contractor involved in the project, seeking damages for his injuries. The suit against PGS remains pending, with a trial currently expected in February 2017. The company is unable at this time to estimate the possible loss or range of loss with respect to this matter. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows. New Mexico Gas Company Legal Proceedings In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business). In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.” In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgment in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment. In late May 2016, a settlement was reached with all the named plaintiffs in the subrogation lawsuits. A motion to dismiss the appeal was granted by the court on Aug. 2, 2016. The settlements were not material to the company. Proceedings in connection with the Merger with Emera Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction. Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida. They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger. Several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits were consolidated per court order. Since the consolidation, two of the complaints were amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed. The company also received two separate shareholder demand letters from purported shareholders of the company. Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices. One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn. In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger. As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement. In September 2016, a hearing was held to gain preliminary approval of a negotiated stipulation of settlement. After that hearing, the judge entered an order granting preliminary approval of the class action settlement and scheduling a final approval hearing for December 2016. There can be no assurance that the court will grant final approval of the settlement. However, while the outcome of such proceeding remains uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows. Claim in connection with the Sale of TECO Coal As discussed in Note 15 TECO Guatemala Holdings, LLC v. The Republic of Guatemala On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. On Apr. 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21.1 million award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the Tribunal’s award of costs to TGH in its original arbitration was based on the Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the Tribunal’s award of costs to TGH. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision. On Sept. 23, 2016, TGH filed a request for resubmission to arbitration. On Oct. 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission, officially commencing the new arbitration and starting the time periods for constitution of the new tribunal. 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 Sept. 30, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates. 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. Merger Commitments In connection with the Merger with Emera, TECO Energy made certain commitments approved by the NMPRC. See Note 14 Guarantees A summary of the face amount or maximum theoretical obligation and the year of expiration under guarantees as of Sept. 30, 2016 is as follows: (millions) Maximum After (1) Theoretical Liabilities Recognized Guarantees for the Benefit of: 2016 2017 2018-2020 2020 Obligation at Sept. 30, 2016 TECO Energy Fuel sales and transportation (2) $ 0.0 $ 0.0 $ 0.0 $ 93.9 $ 93.9 $ 0.0 Letters of indemnity - coal mining permits (3) 0.0 84.5 0.0 0.0 84.5 0.0 $ 0.0 $ 84.5 $ 0.0 $ 93.9 $ 178.4 $ 0.0 (1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. (2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade of its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Sept. 30, 2016. See Note 10 (3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15 Financial Covenants TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.
Tampa Electric Company [Member]
Commitments and Contingencies	8. Commitments and Contingencies Legal Contingencies From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. Peoples Gas 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. 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, a suit was 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 and a PGS contractor involved in the project, seeking damages for his injuries. The suit against PGS remains pending, with a trial currently expected in February 2017. The company is unable at this time to estimate the possible loss or range of loss with respect to this matter. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows. 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 Sept. 30, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates. 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. Financial Covenants TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TEC was in compliance with all applicable financial covenants.

Segment Information

Segment Information	9 Months Ended
Segment Information	Sep. 30, 2016
Segment Information	9. Segment Information TECO Energy is an electric and gas utility holding company with 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. Intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments. Segment Information (1) (millions) Tampa Peoples New Mexico TECO TECO Three months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) Eliminations Energy 2016 Revenues - external $ 585.1 $ 103.3 $ 35.7 $ 0.0 $ 2.6 $ 0.0 $ 726.7 Sales to affiliates 0.8 0.4 0.0 0.0 0.1 (1.3 ) 0.0 Total revenues 585.9 103.7 35.7 0.0 2.7 (1.3 ) 726.7 Total interest charges 22.4 3.7 2.8 0.0 15.2 (0.2 ) 43.9 Net income (loss) from continuing operations 94.1 6.5 (19.8 ) (5) 0.0 (11.4 ) (5) 0.0 69.4 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Net income (loss) $ 94.1 $ 6.5 $ (19.8 ) $ 0.0 $ (11.4 ) $ 0.0 $ 69.4 2015 Revenues - external $ 559.4 $ 88.1 $ 43.7 $ 0.0 $ 2.6 $ 0.0 $ 693.8 Sales to affiliates 0.8 2.0 0.0 0.0 0.0 (2.8 ) 0.0 Total revenues 560.2 90.1 43.7 0.0 2.6 (2.8 ) 693.8 Total interest charges 24.1 3.7 3.2 0.0 15.4 (0.3 ) 46.1 Net income (loss) from continuing operations 82.1 6.2 (2.8 ) 0.0 (20.6 ) 0.0 64.9 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (12.1 ) 0.4 0.0 (11.7 ) Net income (loss) $ 82.1 $ 6.2 $ (2.8 ) $ (12.1 ) $ (20.2 ) $ 0.0 $ 53.2 (millions) Tampa Peoples New Mexico TECO TECO Nine months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) Eliminations Energy 2016 Revenues - external $ 1,506.6 $ 330.0 $ 194.0 $ 0.0 $ 7.9 $ 0.0 $ 2,038.5 Sales to affiliates 3.0 6.8 0.0 0.0 0.1 (9.9 ) 0.0 Total revenues 1,509.6 336.8 194.0 0.0 8.0 (9.9 ) 2,038.5 Total interest charges 68.8 11.1 9.1 0.0 45.3 (0.7 ) 133.6 Net income (loss) from continuing operations 212.9 26.7 (4.8 ) (5) 0.0 (86.2 ) (5) 0.0 148.6 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 0.0 (0.1 ) 0.0 (0.1 ) Net income (loss) $ 212.9 $ 26.7 $ (4.8 ) $ 0.0 $ (86.3 ) $ 0.0 $ 148.5 2015 Revenues - external $ 1,540.8 $ 302.0 $ 216.7 $ 0.0 $ 7.9 $ 0.0 $ 2,067.4 Sales to affiliates 2.4 4.5 0.0 0.0 0.1 (7.0 ) 0.0 Total revenues 1,543.2 306.5 216.7 0.0 8.0 (7.0 ) 2,067.4 Total interest charges 71.2 10.8 9.8 0.0 49.6 (1.0 ) 140.4 Net income (loss) from continuing operations 198.0 28.4 11.0 0.0 (47.2 ) 0.0 190.2 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (69.6 ) 2.4 0.0 (67.2 ) Net income (loss) $ 198.0 $ 28.4 $ 11.0 $ (69.6 ) $ (44.8 ) $ 0.0 $ 123.0 At Sept. 30, 2016 Total assets $ 7,244.9 $ 1,161.5 $ 1,230.4 $ 0.0 $ 2,031.8 $ (2,444.9 ) (4) $ 9,223.7 At Dec. 31, 2015 Total assets (3) $ 7,003.8 $ 1,136.1 $ 1,229.7 $ 0.0 $ 1,945.1 $ (2,381.2 ) (4) $ 8,933.5 (1) All periods have been adjusted to reflect the results from discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15 (2) NMGI is included in the Other segment. (3) Certain prior year amounts have been reclassified to conform to current year presentation. (4) Amounts primarily relate to consolidated tax reclassifications. (5) Includes transaction costs associated with the Merger with Emera. See Note 14
Tampa Electric Company [Member]
Segment Information	9. Segment Information (millions) Tampa Tampa Electric Three months ended Sept. 30, Electric PGS Eliminations Company 2016 Revenues - external $ 585.9 $ 103.2 $ 0.0 $ 689.1 Intracompany sales 0.0 0.5 (0.5 ) 0.0 Total revenues 585.9 103.7 (0.5 ) 689.1 Total interest charges 22.4 3.7 0.0 26.1 Net income $ 94.1 $ 6.5 $ 0.0 $ 100.6 2015 Revenues - external $ 560.1 $ 88.1 $ 0.0 $ 648.2 Intracompany sales 0.1 2.0 (2.1 ) 0.0 Total revenues 560.2 90.1 (2.1 ) 648.2 Total interest charges 24.1 3.7 0.0 27.8 Net income $ 82.1 $ 6.2 $ 0.0 $ 88.3 Nine months ended Sept. 30, 2016 Revenues - external $ 1,508.9 $ 330.0 $ 0.0 $ 1,838.9 Intracompany sales 0.7 6.8 (7.5 ) 0.0 Total revenues 1,509.6 336.8 (7.5 ) 1,838.9 Total interest charges 68.8 11.1 (0.1 ) 79.8 Net income $ 212.9 $ 26.7 $ 0.0 $ 239.6 2015 Revenues - external $ 1,542.9 $ 302.0 $ 0.0 $ 1,844.9 Intracompany sales 0.3 4.5 (4.8 ) 0.0 Total revenues 1,543.2 306.5 (4.8 ) 1,844.9 Total interest charges 71.2 10.8 0.0 82.0 Net income $ 198.0 $ 28.4 $ 0.0 $ 226.4 Total assets at Sept. 30, 2016 $ 7,244.9 $ 1,161.5 $ (452.6 ) (2 ) $ 7,953.8 Total assets at Dec. 31, 2015 (1) $ 7,003.8 $ 1,136.1 $ (431.3 ) (2 ) $ 7,708.6 (1) Certain prior year amounts have been reclassified to conform to current year presentation. (2) Amounts relate to consolidated tax reclassifications.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2016
Accounting for Derivative Instruments and Hedging Activities	10. 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, PGS and NMGC; • To optimize the utilization of NMGC’s physical natural gas storage capacity; and • To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates. TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ 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 11 The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase and sale of natural gas for the benefit of its regulated companies’ ratepayers. These standards, in accordance with the FPSC and NMPRC, 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 Sept. 30, 2016, all of the company’s physical contracts qualify for the NPNS exception with the exception of a minor amount of forward purchases and sales entered into by NMGC to optimize its gas storage capacity. The derivatives that are designated as cash flow hedges at Sept. 30, 2016 and Dec. 31, 2015 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $2.2 million and $0.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.7 million and $26.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties. All of the derivative assets and liabilities at Sept. 30, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Sept. 30, 2016, net pretax gains of $0.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months. The Sept. 30, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12 For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2016 and 2015 is presented in Note 12 The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years: Derivative Volumes Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 14.2 2017 0.0 32.8 2018 0.0 5.3 Total 0.0 52.3 The company is exposed to credit risk by 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. 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 Sept. 30, 2016, 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 generally do not require a nonperformance risk adjustment 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. 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 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.
Tampa Electric Company [Member]
Accounting for Derivative Instruments and Hedging Activities	10. Accounting for Derivative Instruments and Hedging Activities From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes: • To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and • To limit the exposure to interest rate fluctuations on debt securities. TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. 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 11 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 Sept. 30, 2016, all of TEC’s physical contracts qualify for the NPNS exception. The derivatives that are designated as cash flow hedges at Sept. 30, 2016 and Dec. 31, 2015 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $1.5 million and $0.0 as of Sept. 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.5 million and $26.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties. All of the derivative assets and liabilities at Sept. 30, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Sept. 30, 2016, net pretax losses of $0.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months. The Sept. 30, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12 For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2016 and 2015 is presented in Note 12 The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Sept. 30, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 7.7 2017 0.0 23.2 2018 0.0 5.3 Total 0.0 36.2 TEC is exposed to credit risk by 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 Sept. 30, 2016, 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 generally do not require a nonperformance risk adjustment 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. 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 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.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
Fair Value Measurements	Sep. 30, 2016
Fair Value Measurements	11. Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance: (A) Market approach : Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; (B) Cost approach Amount that would be required to replace the service capacity of an asset (replacement cost); and (C) Income approach Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). The fair value of financial instruments is determined by using various market data and other valuation techniques. 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 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. Recurring Fair Value Measures As of Sept. 30, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 2.2 $ 0.0 $ 2.2 Liabilities Natural gas derivatives $ 0.0 $ 1.7 $ 0.0 $ 1.7 As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 0.2 $ 0.0 $ 0.2 Liabilities Natural gas derivatives $ 0.0 $ 26.2 $ 0.0 $ 26.2 The natural gas derivatives are OTC swap, forward and option instruments. Fair values of swaps and forwards are estimated utilizing the market approach. The price of swaps and forwards are calculated using observable NYMEX quoted closing prices of exchange-traded futures. Fair values of options are estimated utilizing the income approach. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap, forward and option positions to determine the fair value (see Note 10 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 Sept. 30, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented. As of Sept. 30, 2016 and Dec. 31, 2015, the carrying value of the company’s short-term debt is not materially different from the fair value due to the short-term nature of the instruments and because the stated rates approximate market rates. The fair value is determined using Level 2 measurements. See Note 7
Tampa Electric Company [Member]
Fair Value Measurements	11. Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance: (A) Market approach : Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; (B) Cost approach Amount that would be required to replace the service capacity of an asset (replacement cost); and (C) Income approach Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). The fair value of financial instruments is determined by using various market data and other valuation techniques. The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis. As 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. Recurring Derivative Fair Value Measures As of Sept. 30, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0.0 $ 1.5 $ 0.0 $ 1.5 Liabilities Natural gas swaps $ 0.0 $ 1.5 $ 0.0 $ 1.5 As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.2 $ 0.0 $ 26.2 Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 10 TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Sept. 30, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Other Comprehensive Income

Other Comprehensive Income	9 Months Ended
Other Comprehensive Income	Sep. 30, 2016
Other Comprehensive Income	12. Other Comprehensive Income TECO Energy reported the following OCI related to changes in the fair value of cash flow hedges, recognized cost due to curtailment, change in benefit obligation due to remeasurement and amortization of unrecognized benefit costs associated with the company’s postretirement plans: Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2016 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income (1) 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Gain on cash flow hedges 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Amortization of unrecognized benefit costs and other (2) 0.8 (0.3 ) 0.5 1.3 (0.5 ) 0.8 Change in benefit obligation due to remeasurement (3) (11.2 ) 4.3 (6.9 ) (11.2 ) 4.3 (6.9 ) Recognized cost due to curtailment (4) 0.0 0.0 0.0 0.1 0.0 0.1 Total other comprehensive loss $ (10.1 ) $ 3.9 $ (6.2 ) $ (8.8 ) $ 3.4 $ (5.4 ) 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income (1) 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Amortization of unrecognized benefit costs (2) 0.4 (0.2 ) 0.2 2.9 (1.1 ) 1.8 Change in benefit obligation due to valuation (5) (8.7 ) 3.0 (5.7 ) (8.7 ) 3.0 (5.7 ) Recognized cost due to settlement (6) 12.1 (4.4 ) 7.7 12.1 (4.4 ) 7.7 Total other comprehensive income $ 4.1 $ (1.7 ) $ 2.4 $ 11.6 $ (4.5 ) $ 7.1 (1) Related to interest rate contracts recognized in Interest expense. (2) Related to postretirement benefits. See Note 5 (3) Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 (4) Related to the estimated curtailment loss for the SERP. See Note 5 (5) Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI. (6) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 15 Accumulated Other Comprehensive Loss (millions) Sept. 30, 2016 Dec. 31, 2015 Unamortized pension loss and prior service credit (1) $ (37.7 ) $ (34.2 ) Unamortized other benefit gains, prior service costs and transition obligations (2) 23.1 25.6 Net unrealized losses from cash flow hedges (3) (3.0 ) (3.6 ) Total accumulated other comprehensive loss $ (17.6 ) $ (12.2 ) (1) Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. (2) Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. (3) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	12. Other Comprehensive Income Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2016 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Gain on cash flow hedges 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Total other comprehensive income $ 0.3 $ (0.1 ) $ 0.2 $ 1.0 $ (0.4 ) $ 0.6 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Total other comprehensive income $ 0.3 $ (0.1 ) $ 0.2 $ 5.3 $ (2.0 ) $ 3.3 Accumulated Other Comprehensive Loss (millions) Sept. 30, 2016 Dec. 31, 2015 Net unrealized losses from cash flow hedges (1) $ (3.0 ) $ (3.6 ) Total accumulated other comprehensive loss $ (3.0 ) $ (3.6 ) (1) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Variable Interest Entities

Variable Interest Entities	9 Months Ended
Variable Interest Entities	Sep. 30, 2016
Variable Interest Entities	13. Variable Interest Entities The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Tampa Electric 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 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric 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, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $19.1 million and $48.1 million under these PPAs for the three and nine months ended Sept. 30, 2016, respectively, and $10.7 million and $26.0 million for the three and nine months ended Sept. 30, 2015, respectively. The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.
Tampa Electric Company [Member]
Variable Interest Entities	13. Variable Interest Entities The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Tampa Electric 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 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric 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, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $19.1 million and $48.1 million under these PPAs for the three and nine months ended Sept. 30, 2016, respectively, and $10.7 million and $26.0 million for the three and nine months ended Sept. 30, 2015, respectively. TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

Mergers and Acquisitions

Mergers and Acquisitions	9 Months Ended
Mergers and Acquisitions	Sep. 30, 2016
Mergers and Acquisitions	14. Mergers and Acquisitions Merger with Emera Inc. Description of Transaction On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion. The Merger Agreement requires Emera, among other things, (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those that they received as of immediately prior to the closing. Merger-Related Regulatory Matters On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the then pending proceeding seeking the approval of the Merger by the NMPRC. On May 2, 2016, the Hearing Examiner held a hearing to consider the stipulation agreement. On June 8, 2016, the Hearing Examiner filed a Certificate of Stipulation, recommending approval by the NMPRC of the stipulation with respect to which all intervenors had either consented or filed a notice of non-opposition. On June 22, 2016, the NMPRC approved the stipulation, and an order was entered on that same day. As part of the stipulation agreement filed with the NMPRC, upon closing of the Merger, NMGC agreed, among other things, to: • make commitments to charitable contributions and enterprises engaged in economic and business development in New Mexico of $0.8 million annually for three years, • continue to provide an annual bill reduction credit of $4 million through June 30, 2018, • evaluate and construct, at shareholder expense, an enlarged pipeline from its current system to the New Mexico/Mexican border at an estimated cost of approximately $5 million, • establish, at shareholder expense, a matching fund of $10 million to extend its natural gas infrastructure to currently underserved or unserved areas in New Mexico, and • contribute, at shareholder expense, $5 million within 5 years to economic development projects or programs throughout New Mexico. The company recorded the pretax costs of $30.4 million (or approximately $17.7 million after tax) related to these commitments in the three months ended Sept. 30, 2016. The bill credit of $8.0 million was recognized as a reduction in “Regulated gas revenues” and the remaining items recorded in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income for the three and nine months ended Sept. 30, 2016. As of Sept. 30, 2016, approximately $30 million remains to be paid and is included in “Other” in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016. Transaction-Related Costs In addition to the Merger-related regulatory matters above, during the three and nine months ended Sept. 30, 2016, TECO Energy also incurred approximately $15.5 million and $87.0 million, respectively, of pretax transaction-related costs ($9.6 million and $68.1 million after tax, respectively), compared with approximately $15.4 million of pretax transaction-related costs during the three and nine months ended Sept. 30, 2015. These costs are presented in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income. For the three months ended Sept. 30, 2016, the $15.5 million of costs are primarily for accelerated vesting of outstanding stock-based compensation awards in accordance with the Merger Agreement and other employee-related costs. For the nine months ended Sept. 30, 2016, the costs also include $27.7 million of investment banking, legal and other consultant costs, $42.4 million for change-in-control and other compensation payments, and $1.3 million for a non-cash SERP curtailment charge recorded in the second quarter. During the third quarter of 2016, Emera contributed $22 million to TECO Energy primarily related to funding accelerated stock compensation payments. Transaction-related costs expensed and paid through Sept. 30, 2016 have been reflected in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016. As of Sept. 30, 2016, approximately $20 million remains to be paid. These remaining costs are expected to be paid primarily in the first quarter of 2017 and are included in “Accounts payable” in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016. See Notes 4 and 5 Dividends Paid On June 22, 2016, in accordance with the Merger Agreement, the TECO Energy board of directors declared a special pro-rated dividend at the then-current rate of $0.002527 per share per day that accrued from May 16, 2016 (the prior TECO Energy dividend record date) until and including June 30, 2016 (the day prior to the effective date of the Merger). This dividend was accrued on the company’s Consolidated Condensed Balance Sheet as of June 30, 2016. On July 12, 2016, TECO Energy paid this dividend of $26.8 million to shareholders of record as of the close of business on the last trading day prior to the effective date of the Merger.
Tampa Electric Company [Member]
Mergers and Acquisitions	14. Mergers and Acquisitions Merger with Emera Inc. As disclosed in Note 1, Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion). The Merger Agreement requires Emera, among other things, (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s and TEC’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those that they received as of immediately prior to the closing.

Discontinued Operations and Ass

Discontinued Operations and Asset Impairments	9 Months Ended
Discontinued Operations and Asset Impairments	Sep. 30, 2016
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations and Asset Impairments	15. Discontinued Operations and Asset Impairments TECO Coal On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian. The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian (see description of guarantees in Note 8 Note 8 Since the closing of the sale, TECO Energy has not had influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance. TECO Guatemala In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries 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 (see Note 8 Combined Components of Discontinued Operations The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala: Components of income from discontinued operations Three months ended Nine months ended Sept. 30, Sept. 30, (millions) 2016 2015 2016 2015 Revenues—TECO Coal $ 0.0 $ 51.6 $ 0.0 $ 200.4 Loss from operations—TECO Coal (0.1 ) (7.4 ) (0.2 ) (16.4 ) Loss on sale—TECO Coal 0.0 (10.0 ) 0.0 (10.0 ) Loss on impairment—TECO Coal 0.0 0.0 0.0 (78.6 ) Loss from operations—TECO Guatemala (0.1 ) (0.4 ) (0.2 ) (0.5 ) Loss from discontinued operations—TECO Coal (0.1 ) (17.4 ) (0.2 ) (105.0 ) Loss from discontinued operations—TECO Guatemala (0.1 ) (0.4 ) (0.2 ) (0.5 ) Loss from discontinued operations (0.2 ) (17.8 ) (0.4 ) (105.5 ) Benefit for income taxes 0.2 6.1 0.3 38.3 Loss from discontinued operations, net $ 0.0 $ (11.7 ) $ (0.1 ) $ (67.2 )

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	9 Months Ended
Summary of Significant Accounting Policies (Policies)	Sep. 30, 2016
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries. See Note 14
Revenues	Revenues As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $71.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.
Accounting for Franchise Fees and Gross Receipt Taxes	Accounting for Franchise Fees and Gross Receipt Taxes Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, compared to $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.
Tampa Electric Company [Member]
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation TEC is a wholly owned subsidiary of TECO Energy. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS. For the periods presented, no VIEs have been consolidated (see Note 13 Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. Note 14
Revenues	Revenues As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $63.7 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.
Accounting for Franchise Fees and Gross Receipt Taxes	Accounting for Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, and $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively.

Regulatory (Tables)

Regulatory (Tables)	9 Months Ended
Regulatory (Tables)	Sep. 30, 2016
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2016 Dec. 31, 2015 Regulatory assets: Regulatory tax asset (1) $ 83.4 $ 74.7 Cost-recovery clauses - deferred balances (2) 4.5 5.5 Cost-recovery clauses - offsets to derivative liabilities (2) 2.1 26.5 Environmental remediation (3) 54.8 54.0 Postretirement benefits (4) 296.4 240.6 Deferred bond refinancing costs (5) 7.1 6.5 Debt basis adjustment (6) 14.9 17.5 Competitive rate adjustment (2) 2.5 2.6 Other 14.8 12.1 Total regulatory assets 480.5 440.0 Less: Current portion 21.8 44.8 Long-term regulatory assets $ 458.7 $ 395.2 Regulatory liabilities: Regulatory tax liability $ 7.2 $ 7.9 Cost-recovery clauses (2) 111.5 55.9 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (7) 670.6 679.9 Bill reduction credit (8) 8.0 0.3 Other 13.6 0.5 Total regulatory liabilities 867.0 800.6 Less: Current portion 148.2 84.8 Long-term regulatory liabilities $ 718.8 $ 715.8 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument. (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (8) See Note 14
Tampa Electric Company [Member]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2016 Dec. 31, 2015 Regulatory assets: Regulatory tax asset (1) $ 83.1 $ 74.6 Cost-recovery clauses - deferred balances (2) 4.4 5.2 Cost-recovery clauses - offsets to derivative liabilities (2) 1.5 26.2 Environmental remediation (3) 54.8 54.0 Postretirement benefits (4) 296.5 238.3 Deferred bond refinancing costs (5) 5.9 6.5 Competitive rate adjustment (2) 2.5 2.6 Other 10.1 10.7 Total regulatory assets 458.8 418.1 Less: Current portion 20.6 44.3 Long-term regulatory assets $ 438.2 $ 373.8 Regulatory liabilities: Regulatory tax liability $ 5.3 $ 5.7 Cost-recovery clauses (2) 107.8 54.2 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (6) 554.8 570.0 Other 13.4 0.7 Total regulatory liabilities 737.4 686.7 Less: Current portion 140.4 83.2 Long-term regulatory liabilities $ 597.0 $ 603.5 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

Employee Postretirement Benef26

Employee Postretirement Benefits (Tables)	9 Months Ended
Employee Postretirement Benefits (Tables)	Sep. 30, 2016
Compensation And Retirement Disclosure [Abstract]
Schedule of Net Periodic Benefit Cost	Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP. Pension Expense (millions) Pension Benefits Other Postretirement Benefits Three months ended Sept. 30, 2016 2015 2016 2015 Components of net periodic benefit expense Service cost $ 4.9 $ 6.7 $ 0.5 $ 0.6 Interest cost 7.2 6.5 2.0 2.0 Expected return on assets (11.5 ) (9.1 ) (0.3 ) (0.3 ) Amortization of: Prior service (benefit) cost 0.0 (0.1 ) (0.6 ) (0.6 ) Actuarial loss 4.8 3.2 0.1 0.0 Regulatory asset 0.0 0.0 0.3 0.3 Curtailment cost 0.0 0.0 0.0 0.0 Settlement cost 0.0 0.0 0.0 0.0 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 5.4 $ 7.2 $ 2.0 $ 2.0 Nine months ended Sept. 30, Components of net periodic benefit expense Service cost $ 13.9 $ 17.6 $ 1.4 $ 1.7 Interest cost 23.6 22.6 6.4 6.1 Expected return on assets (34.2 ) (32.4 ) (0.9 ) (0.8 ) Amortization of: Prior service (benefit) cost 0.2 (0.2 ) (1.9 ) (1.8 ) Actuarial loss 11.7 11.4 0.1 0.0 Regulatory asset 0.0 0.0 0.8 0.8 Curtailment cost 1.3 0.0 0.0 0.0 Settlement cost 0.6 0.0 0.0 0.0 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 17.1 $ 19.0 $ 5.9 $ 6.0

Short-Term Debt (Tables)

Short-Term Debt (Tables)	9 Months Ended
Short-Term Debt (Tables)	Sep. 30, 2016
Short-Term Debt Credit Facilities	Details of the credit facilities and related borrowings are presented in the following table: Credit Facilities Sept. 30, 2016 Dec. 31, 2015 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 0.0 $ 0.5 3-year accounts receivable facility (3) 150.0 49.0 0.0 150.0 61.0 0.0 TECO Energy/TECO Finance: 5-year facility (2)(4) 300.0 150.0 0.0 300.0 163.0 0.0 1-year term facility (4)(5) 400.0 400.0 0.0 0.0 0.0 0.0 New Mexico Gas Company: 5-year facility (2) 125.0 11.5 1.4 125.0 23.0 1.7 Total $ 1,300.0 $ 610.5 $ 1.9 $ 900.0 $ 247.0 $ 2.2 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) This 3-year facility matures Mar. 23, 2018. (4) TECO Finance is the borrower and TECO Energy is the guarantor of this facility. (5) This 1-year facility matures Mar. 14, 2017.
Tampa Electric Company [Member]
Short-Term Debt Credit Facilities	Details of the credit facilities and related borrowings are presented in the following table: Credit Facilities Sept. 30, 2016 Dec. 31, 2015 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 0.0 $ 0.5 3-year accounts receivable facility (3) 150.0 49.0 0.0 150.0 61.0 0.0 Total $ 475.0 $ 49.0 $ 0.5 $ 475.0 $ 61.0 $ 0.5 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) This 3-year facility matures Mar. 23, 2018.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
Commitments and Contingencies (Tables)	Sep. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Guarantees	A summary of the face amount or maximum theoretical obligation and the year of expiration under guarantees as of Sept. 30, 2016 is as follows: (millions) Maximum After (1) Theoretical Liabilities Recognized Guarantees for the Benefit of: 2016 2017 2018-2020 2020 Obligation at Sept. 30, 2016 TECO Energy Fuel sales and transportation (2) $ 0.0 $ 0.0 $ 0.0 $ 93.9 $ 93.9 $ 0.0 Letters of indemnity - coal mining permits (3) 0.0 84.5 0.0 0.0 84.5 0.0 $ 0.0 $ 84.5 $ 0.0 $ 93.9 $ 178.4 $ 0.0 (1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. (2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade of its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Sept. 30, 2016. See Note 10 (3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
Segment Information (Tables)	Sep. 30, 2016
Schedule of Segment Information	TECO Energy is an electric and gas utility holding company with 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. Intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments. Segment Information (1) (millions) Tampa Peoples New Mexico TECO TECO Three months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) Eliminations Energy 2016 Revenues - external $ 585.1 $ 103.3 $ 35.7 $ 0.0 $ 2.6 $ 0.0 $ 726.7 Sales to affiliates 0.8 0.4 0.0 0.0 0.1 (1.3 ) 0.0 Total revenues 585.9 103.7 35.7 0.0 2.7 (1.3 ) 726.7 Total interest charges 22.4 3.7 2.8 0.0 15.2 (0.2 ) 43.9 Net income (loss) from continuing operations 94.1 6.5 (19.8 ) (5) 0.0 (11.4 ) (5) 0.0 69.4 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Net income (loss) $ 94.1 $ 6.5 $ (19.8 ) $ 0.0 $ (11.4 ) $ 0.0 $ 69.4 2015 Revenues - external $ 559.4 $ 88.1 $ 43.7 $ 0.0 $ 2.6 $ 0.0 $ 693.8 Sales to affiliates 0.8 2.0 0.0 0.0 0.0 (2.8 ) 0.0 Total revenues 560.2 90.1 43.7 0.0 2.6 (2.8 ) 693.8 Total interest charges 24.1 3.7 3.2 0.0 15.4 (0.3 ) 46.1 Net income (loss) from continuing operations 82.1 6.2 (2.8 ) 0.0 (20.6 ) 0.0 64.9 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (12.1 ) 0.4 0.0 (11.7 ) Net income (loss) $ 82.1 $ 6.2 $ (2.8 ) $ (12.1 ) $ (20.2 ) $ 0.0 $ 53.2 (millions) Tampa Peoples New Mexico TECO TECO Nine months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) Eliminations Energy 2016 Revenues - external $ 1,506.6 $ 330.0 $ 194.0 $ 0.0 $ 7.9 $ 0.0 $ 2,038.5 Sales to affiliates 3.0 6.8 0.0 0.0 0.1 (9.9 ) 0.0 Total revenues 1,509.6 336.8 194.0 0.0 8.0 (9.9 ) 2,038.5 Total interest charges 68.8 11.1 9.1 0.0 45.3 (0.7 ) 133.6 Net income (loss) from continuing operations 212.9 26.7 (4.8 ) (5) 0.0 (86.2 ) (5) 0.0 148.6 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 0.0 (0.1 ) 0.0 (0.1 ) Net income (loss) $ 212.9 $ 26.7 $ (4.8 ) $ 0.0 $ (86.3 ) $ 0.0 $ 148.5 2015 Revenues - external $ 1,540.8 $ 302.0 $ 216.7 $ 0.0 $ 7.9 $ 0.0 $ 2,067.4 Sales to affiliates 2.4 4.5 0.0 0.0 0.1 (7.0 ) 0.0 Total revenues 1,543.2 306.5 216.7 0.0 8.0 (7.0 ) 2,067.4 Total interest charges 71.2 10.8 9.8 0.0 49.6 (1.0 ) 140.4 Net income (loss) from continuing operations 198.0 28.4 11.0 0.0 (47.2 ) 0.0 190.2 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (69.6 ) 2.4 0.0 (67.2 ) Net income (loss) $ 198.0 $ 28.4 $ 11.0 $ (69.6 ) $ (44.8 ) $ 0.0 $ 123.0 At Sept. 30, 2016 Total assets $ 7,244.9 $ 1,161.5 $ 1,230.4 $ 0.0 $ 2,031.8 $ (2,444.9 ) (4) $ 9,223.7 At Dec. 31, 2015 Total assets (3) $ 7,003.8 $ 1,136.1 $ 1,229.7 $ 0.0 $ 1,945.1 $ (2,381.2 ) (4) $ 8,933.5 (1) All periods have been adjusted to reflect the results from discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15 (2) NMGI is included in the Other segment. (3) Certain prior year amounts have been reclassified to conform to current year presentation. (4) Amounts primarily relate to consolidated tax reclassifications. (5) Includes transaction costs associated with the Merger with Emera. See Note 14
Tampa Electric Company [Member]
Schedule of Segment Information	(millions) Tampa Tampa Electric Three months ended Sept. 30, Electric PGS Eliminations Company 2016 Revenues - external $ 585.9 $ 103.2 $ 0.0 $ 689.1 Intracompany sales 0.0 0.5 (0.5 ) 0.0 Total revenues 585.9 103.7 (0.5 ) 689.1 Total interest charges 22.4 3.7 0.0 26.1 Net income $ 94.1 $ 6.5 $ 0.0 $ 100.6 2015 Revenues - external $ 560.1 $ 88.1 $ 0.0 $ 648.2 Intracompany sales 0.1 2.0 (2.1 ) 0.0 Total revenues 560.2 90.1 (2.1 ) 648.2 Total interest charges 24.1 3.7 0.0 27.8 Net income $ 82.1 $ 6.2 $ 0.0 $ 88.3 Nine months ended Sept. 30, 2016 Revenues - external $ 1,508.9 $ 330.0 $ 0.0 $ 1,838.9 Intracompany sales 0.7 6.8 (7.5 ) 0.0 Total revenues 1,509.6 336.8 (7.5 ) 1,838.9 Total interest charges 68.8 11.1 (0.1 ) 79.8 Net income $ 212.9 $ 26.7 $ 0.0 $ 239.6 2015 Revenues - external $ 1,542.9 $ 302.0 $ 0.0 $ 1,844.9 Intracompany sales 0.3 4.5 (4.8 ) 0.0 Total revenues 1,543.2 306.5 (4.8 ) 1,844.9 Total interest charges 71.2 10.8 0.0 82.0 Net income $ 198.0 $ 28.4 $ 0.0 $ 226.4 Total assets at Sept. 30, 2016 $ 7,244.9 $ 1,161.5 $ (452.6 ) (2 ) $ 7,953.8 Total assets at Dec. 31, 2015 (1) $ 7,003.8 $ 1,136.1 $ (431.3 ) (2 ) $ 7,708.6 (1) Certain prior year amounts have been reclassified to conform to current year presentation. (2) Amounts relate to consolidated tax reclassifications.

Accounting for Derivative Ins30

Accounting for Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Volumes Expected to Settle	The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years: Derivative Volumes Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 14.2 2017 0.0 32.8 2018 0.0 5.3 Total 0.0 52.3
Tampa Electric Company [Member]
Derivative Volumes Expected to Settle	The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Sept. 30, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 7.7 2017 0.0 23.2 2018 0.0 5.3 Total 0.0 36.2

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
Fair Value Measurements (Tables)	Sep. 30, 2016
Schedule of Recurring Fair Value Measurements	Recurring Fair Value Measures As of Sept. 30, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 2.2 $ 0.0 $ 2.2 Liabilities Natural gas derivatives $ 0.0 $ 1.7 $ 0.0 $ 1.7 As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 0.2 $ 0.0 $ 0.2 Liabilities Natural gas derivatives $ 0.0 $ 26.2 $ 0.0 $ 26.2
Tampa Electric Company [Member]
Schedule of Recurring Fair Value Measurements	Recurring Derivative Fair Value Measures As of Sept. 30, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0.0 $ 1.5 $ 0.0 $ 1.5 Liabilities Natural gas swaps $ 0.0 $ 1.5 $ 0.0 $ 1.5 As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.2 $ 0.0 $ 26.2

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	9 Months Ended
Other Comprehensive Income (Tables)	Sep. 30, 2016
Other Comprehensive Income	TECO Energy reported the following OCI related to changes in the fair value of cash flow hedges, recognized cost due to curtailment, change in benefit obligation due to remeasurement and amortization of unrecognized benefit costs associated with the company’s postretirement plans: Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2016 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income (1) 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Gain on cash flow hedges 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Amortization of unrecognized benefit costs and other (2) 0.8 (0.3 ) 0.5 1.3 (0.5 ) 0.8 Change in benefit obligation due to remeasurement (3) (11.2 ) 4.3 (6.9 ) (11.2 ) 4.3 (6.9 ) Recognized cost due to curtailment (4) 0.0 0.0 0.0 0.1 0.0 0.1 Total other comprehensive loss $ (10.1 ) $ 3.9 $ (6.2 ) $ (8.8 ) $ 3.4 $ (5.4 ) 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income (1) 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Amortization of unrecognized benefit costs (2) 0.4 (0.2 ) 0.2 2.9 (1.1 ) 1.8 Change in benefit obligation due to valuation (5) (8.7 ) 3.0 (5.7 ) (8.7 ) 3.0 (5.7 ) Recognized cost due to settlement (6) 12.1 (4.4 ) 7.7 12.1 (4.4 ) 7.7 Total other comprehensive income $ 4.1 $ (1.7 ) $ 2.4 $ 11.6 $ (4.5 ) $ 7.1 (1) Related to interest rate contracts recognized in Interest expense. (2) Related to postretirement benefits. See Note 5 (3) Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 (4) Related to the estimated curtailment loss for the SERP. See Note 5 (5) Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI. (6) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 15
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (millions) Sept. 30, 2016 Dec. 31, 2015 Unamortized pension loss and prior service credit (1) $ (37.7 ) $ (34.2 ) Unamortized other benefit gains, prior service costs and transition obligations (2) 23.1 25.6 Net unrealized losses from cash flow hedges (3) (3.0 ) (3.6 ) Total accumulated other comprehensive loss $ (17.6 ) $ (12.2 ) (1) Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. (2) Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. (3) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2016 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Gain on cash flow hedges 0.3 (0.1 ) 0.2 1.0 (0.4 ) 0.6 Total other comprehensive income $ 0.3 $ (0.1 ) $ 0.2 $ 1.0 $ (0.4 ) $ 0.6 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Total other comprehensive income $ 0.3 $ (0.1 ) $ 0.2 $ 5.3 $ (2.0 ) $ 3.3
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (millions) Sept. 30, 2016 Dec. 31, 2015 Net unrealized losses from cash flow hedges (1) $ (3.0 ) $ (3.6 ) Total accumulated other comprehensive loss $ (3.0 ) $ (3.6 ) (1) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Discontinued Operations and A33

Discontinued Operations and Asset Impairments (Tables)	9 Months Ended
Discontinued Operations and Asset Impairments (Tables)	Sep. 30, 2016
TECO Coal and TECO Guatemala [Member]
Components of Discontinued Operations	The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala: Components of income from discontinued operations Three months ended Nine months ended Sept. 30, Sept. 30, (millions) 2016 2015 2016 2015 Revenues—TECO Coal $ 0.0 $ 51.6 $ 0.0 $ 200.4 Loss from operations—TECO Coal (0.1 ) (7.4 ) (0.2 ) (16.4 ) Loss on sale—TECO Coal 0.0 (10.0 ) 0.0 (10.0 ) Loss on impairment—TECO Coal 0.0 0.0 0.0 (78.6 ) Loss from operations—TECO Guatemala (0.1 ) (0.4 ) (0.2 ) (0.5 ) Loss from discontinued operations—TECO Coal (0.1 ) (17.4 ) (0.2 ) (105.0 ) Loss from discontinued operations—TECO Guatemala (0.1 ) (0.4 ) (0.2 ) (0.5 ) Loss from discontinued operations (0.2 ) (17.8 ) (0.4 ) (105.5 ) Benefit for income taxes 0.2 6.1 0.3 38.3 Loss from discontinued operations, net $ 0.0 $ (11.7 ) $ (0.1 ) $ (67.2 )

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	$ 71.3		$ 71.3		$ 81.1
Franchise fees and gross receipts taxes	32.6	$ 31.7	89.2	$ 88.3
Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	63.7		63.7		$ 53.7
Franchise fees and gross receipts taxes	$ 32.6	$ 31.7	$ 89.2	$ 88.3

New Accounting Pronouncements -

New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Jan. 01, 2016	Sep. 30, 2015	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Cumulative adjustment to retained earnings	$ 2.6
Excess tax benefit reclassified from operating activities to financing activities		$ 1.5
Long-term Debt, Less Amount Due Within One Year [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost			$ 27.7
Long-term Debt, Less Amount Due Within One Year [Member] \| Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost			$ 18.1

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Regulatory assets:
Regulatory assets	$ 480.5	$ 440
Less: Current portion	21.8	44.8
Long-term regulatory assets	458.7	395.2
Regulatory liabilities:
Regulatory liabilities	867	800.6
Less: Current portion	148.2	84.8
Long-term regulatory liabilities	718.8	715.8
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	458.8	418.1
Less: Current portion	20.6	44.3
Long-term regulatory assets	438.2	373.8
Regulatory liabilities:
Regulatory liabilities	737.4	686.7
Less: Current portion	140.4	83.2
Long-term regulatory liabilities	597	603.5
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	83.4	74.7
Regulatory Tax Asset [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	83.1	74.6
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	4.5	5.5
Cost-Recovery Clauses - Deferred Balances [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	4.4	5.2
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	2.1	26.5
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	1.5	26.2
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	54.8	54
Environmental Remediation [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	54.8	54
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	296.4	240.6
Postretirement Benefit Costs [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	296.5	238.3
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	7.1	6.5
Deferred Bond Refinancing Costs [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	5.9	6.5
Debt Basis Adjustment [Member]
Regulatory assets:
Regulatory assets	14.9	17.5
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.5	2.6
Competitive Rate Adjustment [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.5	2.6
Other [Member]
Regulatory assets:
Regulatory assets	14.8	12.1
Other [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	10.1	10.7
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	7.2	7.9
Regulatory Tax Liability [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	5.3	5.7
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	111.5	55.9
Cost-Recovery Clauses [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	107.8	54.2
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Transmission and Delivery Storm Reserve [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	670.6	679.9
Accumulated Reserve - Cost of Removal [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	554.8	570
Bill Reduction Credit [Member]
Regulatory liabilities:
Regulatory liabilities	8	0.3
Other [Member]
Regulatory liabilities:
Regulatory liabilities	13.6	0.5
Other [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	$ 13.4	$ 0.7

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Taxes [Line Items]
Effective tax rate	19.86%	39.12%	34.19%	39.10%
Statutory tax rate			35.00%
Effective tax rate decrease due to federal research and development credits	19.26%	19.26%
Income tax examination period			1 year
Uncertain tax positions	$ 7.7		$ 7.7		$ 0
Taxes accrued	$ 65		$ 65		13.2
Tampa Electric Company [Member]
Income Taxes [Line Items]
Effective tax rate	32.53%	37.73%	34.59%	37.15%
Effective tax rate decrease due to federal research and development credits	5.20%	5.20%
Statutes of limitations			3 years
Income tax examination period			1 year
Uncertain tax positions	$ 6.5		$ 6.5		0
Taxes accrued	74.5		74.5		$ 13.2
Tampa Electric Company [Member] \| Emera Inc. [Member]
Income Taxes [Line Items]
Taxes accrued	$ 14.2		$ 14.2
Minimum [Member]
Income Taxes [Line Items]
Statutes of limitations			3 years
Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations			4 years

Employee Postretirement Benef38

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4.9		$ 6.7	$ 13.9	$ 17.6
Interest cost	7.2		6.5	23.6	22.6
Expected return on assets	(11.5)		(9.1)	(34.2)	(32.4)
Amortization of:
Prior service (benefit) cost	0		(0.1)	0.2	(0.2)
Actuarial loss	4.8		3.2	11.7	11.4
Regulatory asset	0		0	0	0
Curtailment cost	0	$ 1.3	0	1.3	0
Settlement cost	0		0	0.6	0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	5.4		7.2	17.1	19
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.5		0.6	1.4	1.7
Interest cost	2		2	6.4	6.1
Expected return on assets	(0.3)		(0.3)	(0.9)	(0.8)
Amortization of:
Prior service (benefit) cost	(0.6)		(0.6)	(1.9)	(1.8)
Actuarial loss	0.1		0	0.1	0
Regulatory asset	0.3		0.3	0.8	0.8
Curtailment cost	0		0	0	0
Settlement cost	0		0	0	0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 2		$ 2	$ 5.9	$ 6

Employee Postretirement Benef39

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	Jul. 02, 2016	Jan. 01, 2016	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Reclassification of AOCI to net income as part of periodic benefit expense				$ 0.8		$ 0.2	$ 1.8	$ 2.4
Reclassification of regulatory assets to net income as part of periodic benefit expense				3.8		2.6	9.1	7.8
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.00%	7.00%
Reclassification of regulatory assets to net income as part of periodic benefit expense				2.8		2.3	7.6	7
Scenario Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Settlement charge related to the SERP			$ 8
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.00%	7.00%
Discount rate	3.72%	4.685%
Increase in net periodic benefit expense				0.6			0.6
Increase in liability for pension benefits				61.7			61.7
Increase in regulatory asset				54			54
Decrease in accumulated other comprehensive income				7.7			7.7
Employer contributions							37.4	55
Curtailment cost				0	$ 1.3	0	1.3	0
Settlement charge related to the SERP				0		0	0.6	0
Net pension expense				5.4		7.2	17.1	19
Pension Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.72%	4.685%
Increase in net periodic benefit expense				0.8			0.8
Increase in liability for pension benefits				53.3			53.3
Increase in regulatory asset				53.3			53.3
Employer contributions							30.9	43.9
Net pension expense				3.5		3.3	9.6	10.1
Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.667%
Other Postretirement Benefits, NMGC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.687%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.85%
Increase in net periodic benefit expense				0			0
Increase in liability for pension benefits				17.6			17.6
Increase in regulatory asset				14.1			14.1
Decrease in accumulated other comprehensive income				3.5			3.5
Employer contributions							2.7	2.7
Curtailment cost				0		0	0	0
Settlement charge related to the SERP				0		0	0	0
Net pension expense				2		2	5.9	6
Other Postretirement Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.85%	4.667%
Increase in net periodic benefit expense				0.3			0.3
Increase in liability for pension benefits				12.4			12.4
Increase in regulatory asset				12.4			12.4
Net pension expense				$ 1.7		$ 1.4	$ 4.7	$ 4.3

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities (Detail) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Credit Facilities	$ 1,300,000,000	$ 900,000,000
Borrowings Outstanding	610,500,000	247,000,000
Letters of Credit Outstanding	1,900,000	2,200,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	475,000,000	475,000,000
Borrowings Outstanding	49,000,000	61,000,000
Letters of Credit Outstanding	500,000	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	0	0
Letters of Credit Outstanding	500,000	500,000
Tampa Electric Company [Member] \| 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000	150,000,000
Borrowings Outstanding	49,000,000	61,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000	300,000,000
Borrowings Outstanding	150,000,000	163,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] \| 1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	400,000,000	0
Borrowings Outstanding	400,000,000	0
Letters of Credit Outstanding	0	0
New Mexico Gas Company [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	125,000,000	125,000,000
Borrowings Outstanding	11,500,000	23,000,000
Letters of Credit Outstanding	$ 1,400,000	$ 1,700,000

Short-Term Debt - Credit Faci41

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Tampa Electric Company [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member] \| 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018
TECO Energy [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
TECO Energy [Member] \| 1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 14, 2017	Mar. 14, 2017
New Mexico Gas Company [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Mar. 14, 2016	Sep. 30, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity		$ 1,300,000,000	$ 900,000,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.32%	0.89%
Line of Credit Facility maximum borrowing capacity		$ 475,000,000	$ 475,000,000
TECO Energy [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.71%	1.29%
TECO Finance [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.71%	1.29%
Interest rate description		provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, 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 one-month London interbank deposit rate plus 1.00%.
TECO Finance [Member] \| 1-year Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity	$ 400,000,000
Credit facility maturity date	Mar. 14, 2017
TECO Finance [Member] \| Federal Funds Rate [Member]
Line Of Credit Facility [Line Items]
Basis spread on referenced interest rate	0.50%
TECO Finance [Member] \| London Interbank Deposit Rate [Member]
Line Of Credit Facility [Line Items]
Basis spread on referenced interest rate	1.00%
New Mexico Gas Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.71%	1.29%
Minimum [Member] \| Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.125%
Maximum [Member] \| Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.30%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Mar. 15, 2016	Mar. 15, 2012	Mar. 19, 2008	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt, carrying amount				$ 3,490.3		$ 3,822.5
Estimated fair value				3,911.2		4,061.6
Purchase in lieu of redemption				333.3	$ 274.5
HCIDA Pollution Control Revenue Refunding Bonds [Member] \| Held Bonds [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption				232.6
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount				2,162.6		2,245
Estimated fair value				2,505.6		$ 2,433.3
Purchase in lieu of redemption				83.3	$ 83.3
Tampa Electric Company [Member] \| HCIDA Pollution Control Revenue Refunding Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, repurchase date	Mar. 15, 2016	Mar. 15, 2012	Mar. 19, 2008
Purchase in lieu of redemption			$ 86
Stated interest rate	2.00%	1.875%	5.00%
Level 1 [Member]
Debt Instrument [Line Items]
Fair value of debt securities				58.3
Level 1 [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Fair value of debt securities				$ 58.3

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Apr. 05, 2016USD ($)	Dec. 19, 2013USD ($)	Feb. 08, 2011CustomerInsuranceCarrierLawsuit	Sep. 30, 2016USD ($)Claims	Sep. 30, 2015USD ($)	Mar. 31, 2011Customer
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers \| Customer			28,700			32,000
Number of class actions settled \| Claims				2
Number of insurance carriers \| InsuranceCarrier			18
Number of lawsuits for insurance carriers \| Lawsuit			2
Dismissed annulment of the award	$ 21.1
Letters of indemnity coal mining permits					$ 93.8
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites				$ 33.9
PGS [Member] \| Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites				$ 33.9
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Long Term Commitments [Line Items]
Litigation settlement amount		$ 7.5
Damages awarded		$ 21.1
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member] \| U.S. prime rate plus [Member]
Long Term Commitments [Line Items]
Litigation settlement interest		2.00%

Commitments and Contingencies45

Commitments and Contingencies - Guarantees (Detail)	Sep. 30, 2016USD ($)
Guarantee Obligations [Line Items]
Year of expiration 2016	$ 0
Year of expiration 2017	84,500,000
Year of expiration 2018-2020	0
Year of expiration After 2020	93,900,000
Maximum Theoretical Obligation	178,400,000
Liabilities Recognized at Sept. 30, 2016	0
Fuel Sales and Transportation [Member]
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017	0
Year of expiration 2018-2020	0
Year of expiration After 2020	93,900,000
Maximum Theoretical Obligation	93,900,000
Liabilities Recognized at Sept. 30, 2016	0
Letters of Indemnity - Coal Mining Permits
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017	84,500,000
Year of expiration 2018-2020	0
Year of expiration After 2020	0
Maximum Theoretical Obligation	84,500,000
Liabilities Recognized at Sept. 30, 2016	$ 0

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total revenues	$ 726.7	$ 693.8	$ 2,038.5	$ 2,067.4
Total interest charges	43.9	46.1	133.6	140.4
Net income (loss) from continuing operations	69.4	64.9	148.6	190.2
Income (loss) from discontinued operations, net	0	(11.7)	(0.1)	(67.2)
Net income	69.4	53.2	148.5	123
Total assets	9,223.7		9,223.7		$ 8,933.5
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	689.1	648.2	1,838.9	1,844.9
Total interest charges	26.1	27.8	79.8	82
Net income	100.6	88.3	239.6	226.4
Total assets	7,953.8		7,953.8		7,708.6
Tampa Electric Company [Member] \| Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(1.3)	(2.8)	(9.9)	(7)
Total interest charges	(0.2)	(0.3)	(0.7)	(1)
Net income (loss) from continuing operations	0	0	0	0
Income (loss) from discontinued operations, net	0	0	0	0
Net income	0	0	0	0
Total assets	(2,444.9)		(2,444.9)		(2,381.2)
Eliminations [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	(0.5)	(2.1)	(7.5)	(4.8)
Total interest charges	0	0	(0.1)	0
Net income	0	0	0	0
Total assets	(452.6)		(452.6)		(431.3)
Eliminations [Member] \| Tampa Electric Company [Member] \| Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(0.5)	(2.1)	(7.5)	(4.8)
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	726.7	693.8	2,038.5	2,067.4
Revenues - External [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	689.1	648.2	1,838.9	1,844.9
Revenues - External [Member] \| Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Revenues - External [Member] \| Eliminations [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
Sales to Affiliates [Member] \| Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(1.3)	(2.8)	(9.9)	(7)
Tampa Electric [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	585.9	560.2	1,509.6	1,543.2
Total interest charges	22.4	24.1	68.8	71.2
Net income (loss) from continuing operations	94.1	82.1	212.9	198
Income (loss) from discontinued operations, net	0	0	0	0
Net income	94.1	82.1	212.9	198
Total assets	7,244.9		7,244.9		7,003.8
Tampa Electric [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	585.9	560.2	1,509.6	1,543.2
Total interest charges	22.4	24.1	68.8	71.2
Net income	94.1	82.1	212.9	198
Total assets	7,244.9		7,244.9		7,003.8
Tampa Electric [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member] \| Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0.1	0.7	0.3
Tampa Electric [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	585.1	559.4	1,506.6	1,540.8
Tampa Electric [Member] \| Revenues - External [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	585.9	560.1	1,508.9	1,542.9
Tampa Electric [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.8	0.8	3	2.4
PGS [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	103.7	90.1	336.8	306.5
Total interest charges	3.7	3.7	11.1	10.8
Net income (loss) from continuing operations	6.5	6.2	26.7	28.4
Income (loss) from discontinued operations, net	0	0	0	0
Net income	6.5	6.2	26.7	28.4
Total assets	1,161.5		1,161.5		1,136.1
PGS [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	103.7	90.1	336.8	306.5
Total interest charges	3.7	3.7	11.1	10.8
Net income	6.5	6.2	26.7	28.4
Total assets	1,161.5		1,161.5		1,136.1
PGS [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member] \| Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.5	2	6.8	4.5
PGS [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	103.3	88.1	330	302
PGS [Member] \| Revenues - External [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	103.2	88.1	330	302
PGS [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.4	2	6.8	4.5
New Mexico Gas Co. [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	35.7	43.7	194	216.7
Total interest charges	2.8	3.2	9.1	9.8
Net income (loss) from continuing operations	(19.8)	(2.8)	(4.8)	11
Income (loss) from discontinued operations, net	0	0	0	0
Net income	(19.8)	(2.8)	(4.8)	11
Total assets	1,230.4		1,230.4		1,229.7
New Mexico Gas Co. [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	35.7	43.7	194	216.7
New Mexico Gas Co. [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
TECO Coal [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Total interest charges	0	0	0	0
Net income (loss) from continuing operations	0	0	0	0
Income (loss) from discontinued operations, net	0	(12.1)	0	(69.6)
Net income	0	(12.1)	0	(69.6)
Total assets	0		0		0
TECO Coal [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
TECO Coal [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
Other [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.7	2.6	8	8
Total interest charges	15.2	15.4	45.3	49.6
Net income (loss) from continuing operations	(11.4)	(20.6)	(86.2)	(47.2)
Income (loss) from discontinued operations, net	0	0.4	(0.1)	2.4
Net income	(11.4)	(20.2)	(86.3)	(44.8)
Total assets	2,031.8		2,031.8		$ 1,945.1
Other [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.6	2.6	7.9	7.9
Other [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	$ 0.1	$ 0	$ 0.1	$ 0.1

Accounting for Derivative Ins47

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative assets	$ 2,200,000	$ 200,000
Derivative liabilities	1,700,000	26,200,000
Cash collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	500,000
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets	1,500,000	0
Derivative liabilities	1,500,000	26,200,000
Cash collateral posted with or received from any counterparties	0	$ 0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	$ (100,000)
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Sep. 30, 2018
Natural Gas Contracts [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Sep. 30, 2018

Accounting for Derivative Ins48

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Sep. 30, 2016MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Natural Gas Contract Expected to be Settled in Year 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Natural Gas Contract Expected to be Settled in Year 2016 [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Natural Gas Contract Expected to be Settled in Year 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Natural Gas Contract Expected to be Settled in Year 2017 [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Natural Gas Contract Expected to be Settled in Year 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] \| Natural Gas Contract Expected to be Settled in Year 2018 [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	52,300,000
Financial [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36,200,000
Financial [Member] \| Natural Gas Contract Expected to be Settled in Year 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,200,000
Financial [Member] \| Natural Gas Contract Expected to be Settled in Year 2016 [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,700,000
Financial [Member] \| Natural Gas Contract Expected to be Settled in Year 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32,800,000
Financial [Member] \| Natural Gas Contract Expected to be Settled in Year 2017 [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	23,200,000
Financial [Member] \| Natural Gas Contract Expected to be Settled in Year 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,300,000
Financial [Member] \| Natural Gas Contract Expected to be Settled in Year 2018 [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,300,000

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	$ 2.2	$ 0.2
Natural gas derivative liabilities	1.7	26.2
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	1.5	0
Natural gas derivative liabilities	1.5	26.2
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	0	0
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	2.2	0.2
Natural gas derivative liabilities	1.7	26.2
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	1.5
Natural gas derivative liabilities	1.5	26.2
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	2.2	0.2
Natural gas derivative liabilities	1.7	26.2
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	1.5
Natural gas derivative liabilities	1.5	26.2
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0
Natural gas derivative liabilities	$ 0	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 2.2	$ 0.2
Derivative liabilities	1.7	26.2
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	1.5	0
Derivative liabilities	1.5	26.2
Level 3 [Member] \| Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 3 [Member] \| Fair Value, Measurements, Recurring [Member] \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	$ 0	$ 0

Other Comprehensive Income - Ac

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Income) (Detail) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015		Dec. 31, 2015
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income (loss), Gross		$ (10.1)		$ 4.1		$ (8.8)		$ 11.6
Amortization of unrecognized benefit costs and other, Gross		0.8	[1]	0.4	[2]	1.3	[1]	2.9	[2]
Change in benefit obligation due to remeasurement, Gross	[3]	(11.2)				(11.2)
Recognized cost due to curtailment , Gross	[2]	0				0.1
Change in benefit obligation due to valuation, Gross	[4]			(8.7)				(8.7)
Recognized cost due to settlement, Gross	[5]			12.1				12.1
Total other comprehensive income (loss), Tax		3.9		(1.7)		3.4		(4.5)
Amortization of unrecognized benefit costs and other, Tax	[1]	(0.3)		(0.2)		(0.5)		(1.1)
Change in benefit obligation due to remeasurement, Tax	[3]	4.3				4.3
Recognized cost due to curtailment , Tax	[2]	0				0
Change in benefit obligation due to valuation, Tax	[4]			3				3
Recognized cost due to settlement, Tax	[5]			(4.4)				(4.4)
Other comprehensive income (loss), net of tax		(6.2)		2.4		(5.4)		7.1
Amortization of unrecognized benefit costs and other, Net	[1]	0.5		0.2		0.8		1.8
Change in benefit obligation due to remeasurement, Net	[3]	(6.9)				(6.9)
Recognized cost due to curtailment , Net		0	[2]	0		0.1	[2]	0
Change in benefit obligation due to valuation, Net	[4]			(5.7)				(5.7)
Recognized cost due to settlement, Net		0		7.7	[5]	0		7.7	[5]
Unamortized pension loss and prior service credit	[6]	(37.7)				(37.7)				$ (34.2)
Unamortized other benefit gains, prior service costs and transition obligations	[7]	23.1				23.1				25.6
Net unrealized losses from cash flow hedges	[8]	(3)				(3)				(3.6)
Total accumulated other comprehensive loss		(17.6)				(17.6)				(12.2)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income (loss), Gross		0.3		0.3		1		5.3
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(0.4)		(2)
Other comprehensive income (loss), net of tax		0.2		0.2		0.6		3.3
Net unrealized losses from cash flow hedges	[8]	(3)				(3)				(3.6)
Total accumulated other comprehensive loss		(3)				(3)				$ (3.6)
Accumulated Gain on Cash Flow Hedges [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0		0		0		4.3
Reclassification from AOCI to net income, Gross	[9]	0.3		0.3		1		1
Total other comprehensive income (loss), Gross		0.3		0.3		1		5.3
Unrealized gain on cash flow hedges, Tax		0		0		0		(1.5)
Reclassification from AOCI to net income, Tax	[9]	(0.1)		(0.1)		(0.4)		(0.5)
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(0.4)		(2)
Unrealized gain on cash flow hedges, Net		0		0		0		2.8
Reclassification from AOCI to net income, Net	[9]	0.2		0.2		0.6		0.5
Other comprehensive income (loss), net of tax		0.2		0.2		0.6		3.3
Accumulated Gain on Cash Flow Hedges [Member] \| Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0		0		0		4.3
Reclassification from AOCI to net income, Gross		0.3		0.3		1		1
Total other comprehensive income (loss), Gross		0.3		0.3		1		5.3
Unrealized gain on cash flow hedges, Tax		0		0		0		(1.5)
Reclassification from AOCI to net income, Tax		(0.1)		(0.1)		(0.4)		(0.5)
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(0.4)		(2)
Unrealized gain on cash flow hedges, Net		0		0		0		2.8
Reclassification from AOCI to net income, Net		0.2		0.2		0.6		0.5
Other comprehensive income (loss), net of tax		$ 0.2		$ 0.2		$ 0.6		$ 3.3

[1]	Related to postretirement benefits. See Note 5 for additional information.
[2]	Related to the estimated curtailment loss for the SERP. See Note 5 for additional information.
[3]	Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 for additional information.
[4]	Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI.
[5]	Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 15 for additional information.
[6]	Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
[7]	Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
[8]	Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
[9]	Related to interest rate contracts recognized in Interest expense.

Other Comprehensive Income - 52

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 1.9	$ 2.3
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	1.9	2.3
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	23.5	21.5
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	$ 14.3	$ 16.1

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)MW	Sep. 30, 2015USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power \| $	$ 38.3	$ 23.8	$ 80.5	$ 60.5
Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power \| $	38.3	23.8	80.5	60.5
Power Purchase Agreements [Member] \| Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power \| $	19.1	10.7	48.1	26
Power Purchase Agreements [Member] \| Variable Interest Entity Not Primary Beneficiary [Member] \| Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power \| $	$ 19.1	$ 10.7	$ 48.1	$ 26
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range \| MW			117
Minimum [Member] \| Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range \| MW			117
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range \| MW			250
Maximum [Member] \| Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range \| MW			250

Mergers and Acquisitions - Addi

Mergers and Acquisitions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Jul. 12, 2016	Jul. 02, 2016	Jun. 22, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Jul. 01, 2016
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding								$ 27.55
Aggregate purchase price		$ 10,700
Senior secured notes								$ 4,200
Other expenses yet to be paid				$ 30		$ 30
Business combination transaction related costs				15.5	$ 15.4	87	$ 15.4
Business combination transaction related costs, after tax				9.6		68.1
Investment banking, legal and other consultant costs						27.7
Change-in-control and other compensation payments						42.4
Non-cash SERP curtailment charge						1.3
Contributions from parent				22
Accelerated vesting of outstanding stock-based compensation awards				15.5
Business combination transaction related costs payable				20		20
Dividends payable, declared date			Jun. 22, 2016
Declared a special pro-rated dividend			$ 0.002527
Dividends paid	$ 26.8
Tampa Electric Company [Member] \| Emera Inc. [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding								$ 27.55
Aggregate purchase price		$ 10,700
Senior secured notes								$ 4,200
Senior secured notes								2,300
Regulated Gas Revenues [Member]
Business Acquisition [Line Items]
Recognition of bill credit				8		8
Pipeline [Member]
Business Acquisition [Line Items]
Other commitment								5
Natural Gas Infrastructure [Member]
Business Acquisition [Line Items]
Other commitment								10
Annual Commitment to Charitable Contributions and Certain Enterprises [Member]
Business Acquisition [Line Items]
Other commitment								0.8
Period of commitment		3 years
Annual Bill Reduction Credit [Member]
Business Acquisition [Line Items]
Other commitment								4
Economic Development Projects [Member]
Business Acquisition [Line Items]
Other commitment								$ 5
Period of commitment		5 years
Commitments to NMPRC, Pretax [Member]
Business Acquisition [Line Items]
Other commitment				30.4		30.4
Commitments to NMPRC, After Tax [Member]
Business Acquisition [Line Items]
Other commitment				$ 17.7		$ 17.7

Discontinued Operations and A55

Discontinued Operations and Asset Impairments - Additional Information (Detail) $ in Millions	Sep. 21, 2015USD ($)
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Contingent payments	$ 60

Discontinued Operations and A56

Discontinued Operations and Asset Impairments - Components of Discontinued Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from discontinued operations	$ (0.2)	$ (17.8)	$ (0.4)	$ (105.5)
Benefit for income taxes	0.2	6.1	0.3	38.3
Loss from discontinued operations, net	0	(11.7)	(0.1)	(67.2)
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues	0	51.6	0	200.4
Loss from operations	(0.1)	(7.4)	(0.2)	(16.4)
Loss on sale	0	(10)	0	(10)
Loss on impairment	0	0	0	(78.6)
Loss from discontinued operations	(0.1)	(17.4)	(0.2)	(105)
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from operations	(0.1)	(0.4)	(0.2)	(0.5)
Loss from discontinued operations	$ (0.1)	$ (0.4)	$ (0.2)	$ (0.5)