10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

OR

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

For the transition period from to

Commission File No	Exact name of each registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-5007	TAMPA ELECTRIC COMPANY	59-0475140
	(a Florida corporation) TECO Plaza 702 N. Franklin Street Tampa, Florida 33602 (813) 228-1111

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     YES  ☒    NO  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on their corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).     YES  ☒    NO  ☐

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark whether Tampa Electric Company has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

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

As of May 9, 2017, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

ACRONYMS

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

Term	Meaning
ABS	asset-backed security
ADR	American depository receipts
AFUDC	allowance for funds used during construction
AFUDC-debt	debt component of allowance for funds used during construction
AFUDC-equity	equity component of allowance for funds used during construction
AMT	alternative minimum tax
AOCI	accumulated other comprehensive income
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
BACT	Best Available Control Technology
CAIR	Clean Air Interstate Rule
CCRs	coal combustion residuals
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CO2	carbon dioxide
CT	combustion turbine
ECRC	environmental cost recovery clause
EEI	Edison Electric Institute
EGWP	Employee Group Waiver Plan
Emera	Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada
EPA	U.S. Environmental Protection Agency
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
EUSHI	Emera US Holdings Inc., a wholly owned subsidiary of Emera, which is the sole shareholder of TECO Energy’s common stock
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FPSC	Florida Public Service Commission
GHG	greenhouse gas(es)
HAFTA	Highway and Transportation Funding Act
HCIDA	Hillsborough County Industrial Development Authority
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ITCs	investment tax credits
KW	kilowatt(s)
MAP-21	Moving Ahead for Progress in the 21st Century Act
MBS	mortgage-backed securities
MD&A	the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger	Merger of Merger Sub Company with and into TECO Energy, with TECO Energy as the surviving corporation
MGP	manufactured gas plant
Merger Agreement	Agreement and Plan of Merger dated September 4, 2015, by and among TECO Energy, Emera and Merger Sub Company
Merger Sub Company	Emera US Inc., a Florida corporation
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MMBTU	one million British Thermal Units
MRV	market-related value
MW	megawatt(s)
MWH	megawatt-hour(s)

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Term	Meaning
NAESB	North American Energy Standards Board
NAV	net asset value
NMGC	New Mexico Gas Company, Inc.
Note	Note to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income
OPC	Office of Public Counsel
OPEB	other postretirement benefits
OTC	over-the-counter
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
R&D	research and development
REIT	real estate investment trust
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
ROW	rights-of-way
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SERP	Supplemental Executive Retirement Plan
STIF	short-term investment fund
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TEC	Tampa Electric Company
TECO Energy	TECO Energy, Inc., the direct parent company of Tampa Electric Company
TSI	TECO Services, Inc.
U.S. GAAP	generally accepted accounting principles in the United States
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	March 31,			December 31,
(millions)	2017			2016
Property, plant and equipment
Utility plant
Electric	$	8,281		$	7,624
Gas		1,529			1,503
Construction work in progress		262			892
Utility plant, at original costs		10,072			10,019
Accumulated depreciation		(2,839	)		(2,826	)
Utility plant, net		7,233			7,193
Other property		11			10
Total property, plant and equipment, net		7,244			7,203
Current assets
Cash and cash equivalents		10			10
Receivables, less allowance for uncollectibles of $3 and $1 at March 31, 2017 and           December 31, 2016, respectively		200			206
Due from affiliates		2			7
Inventories, at average cost
Fuel		78			77
Materials and supplies		93			86
Derivative assets		6			15
Regulatory assets		29			28
Prepayments and other current assets		22			21
Total current assets		440			450
Deferred debits
Regulatory assets		390			393
Other		31			37
Total deferred debits		421			430
Total assets	$	8,105		$	8,083

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	March 31,			December 31,
(millions)	2017			2016
Capitalization
Common stock	$	2,483		$	2,456
Accumulated other comprehensive loss		(3	)		(3	)
Retained earnings		303			311
Total capital		2,783			2,764
Long-term debt		2,163			2,163
Total capitalization		4,946			4,927
Current liabilities
Notes payable		276			170
Accounts payable		154			262
Due to affiliates		19			25
Customer deposits		141			146
Regulatory liabilities		124			154
Accrued interest		38			16
Accrued taxes		29			12
Other		10			11
Total current liabilities		791			796
Deferred credits
Deferred income taxes		1,425			1,407
Investment tax credits		22			11
Regulatory liabilities		584			591
Deferred credits and other liabilities		337			351
Total deferred credits		2,368			2,360
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	8,105		$	8,083

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended March 31,
(millions)	2017			2016
Revenues
Electric	$	442		$	424
Gas		111			127
Total revenues		553			551
Expenses
Fuel		131			115
Purchased power		7			14
Cost of natural gas sold		36			50
Operations and maintenance		128			121
Depreciation and amortization		85			81
Taxes, other than income		49			49
Total expenses		436			430
Income from operations		117			121
Other income
Allowance for equity funds used during construction		1			6
Other income, net		2			1
Total other income		3			7
Interest charges
Interest on long-term debt		28			29
Interest expense		2			1
Allowance for borrowed funds used during construction		(1	)		(2	)
Total interest charges		29			28
Income before provision for income taxes		91			100
Provision for income taxes		35			37
Net income	$	56		$	63
Comprehensive income	$	56		$	63

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

6

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended March 31,
(millions)	2017			2016
Cash flows from operating activities
Net income	$	56		$	63
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		85			81
Deferred income taxes and investment tax credits		35			30
Allowance for equity funds used during construction		(1	)		(6	)
Deferred recovery clauses		(23	)		27
Receivables, less allowance for uncollectibles		11			25
Inventories		(8	)		(10	)
Taxes accrued		16			82
Interest accrued		22			24
Accounts payable		(101	)		(41	)
Other		(16	)		(7	)
Cash flows from operating activities		76			268
Cash flows from investing activities
Capital expenditures		(143	)		(151	)
Cash flows used in investing activities		(143	)		(151	)
Cash flows from financing activities
Common stock		27			25
Net increase (decrease) in short-term debt		106			(61	)
Dividends		(65	)		(62	)
Other financing activities		(1	)		0
Cash flows from (used in) financing activities		67			(98	)
Net increase in cash and cash equivalents		0			19
Cash and cash equivalents at beginning of period		10			9
Cash and cash equivalents at end of period	$	10		$	28
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(12	)	$	(5	)

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

7

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2016 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

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.

Intercompany balances and transactions within the divisions 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 March 31, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended March 31, 2017 and 2016. The results of operations for the three months ended March 31, 2017 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2017.

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.

TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.

Revenues

As of March 31, 2017 and December 31, 2016, unbilled revenues of $56 million and $54 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 $26 million and $28 million for the three months ended March 31, 2017 and 2016, respectively.

2. New Accounting Pronouncements

Future Accounting Pronouncements

TEC considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the FASB.  The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in TEC’s 2016 Annual Report on Form 10-K, with the exception of the items noted below.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, which has been codified as ASC Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. TEC will adopt this guidance effective January 1, 2018. 

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While TEC does not currently expect the impact to be significant, TEC is continuing to evaluate the impact of the adoption of this standard on its consolidated financial statements. TEC implemented a project plan in 2016, and is in the process of reviewing material revenue streams in line with this plan, with conclusions on the impact on the streams expected in the second and third quarter of 2017. In addition, TEC is evaluating the available adoption methods, the impact of collectibility risk, and disclosure requirements. In the first quarter of 2017, TEC has concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. TEC is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

3. Regulatory

Base Rates-Tampa Electric

Tampa Electric’s results reflect a stipulation and settlement agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provides for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software beginning on January 1, 2013.

Storm Damage Cost Recovery-Tampa Electric

As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $9 million of storm costs in 2016. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surcharge to customers during the five-month period ended December 31, 2017. Subsequent communications with FPSC staff and signatories to the 2013 stipulation and settlement agreement resulted in a conclusion to withdraw the petition, apply the storm costs to the transmission and delivery storm reserve and seek recovery of storm costs once the reserve is fully depleted. See the table below for the regulatory liability.

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Base Rates-PGS

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and decrease the bottom of the ROE range from 9.75% to 9.25%. The new bottom of the ROE range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020. The top of the ROE range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. On February 7, 2017, the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement.

As part of the settlement, PGS and OPC agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million will be amortized over a two-year recovery period beginning in 2016. In 2016, PGS recorded $16 million of this amortization expense. This additional amortization expense in 2016 was offset by the decrease in depreciation expense as discussed above with no impact to 2016 earnings. For the three months ended March 31, 2017, PGS recorded $1 million of amortization expense.  

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: 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)	March 31, 2017		December 31, 2016
Regulatory assets:
Regulatory tax asset (1)	$	85	$	86
Cost-recovery clauses - deferred balances (2)		10		8
Environmental remediation (3)		35		37
Postretirement benefits (4)		269		272
Other		20		18
Total regulatory assets		419		421
Less: Current portion		29		28
Long-term regulatory assets	$	390	$	393
Regulatory liabilities:
Regulatory tax liability	$	12	$	6
Cost-recovery clauses - deferred balances (2)		91		112
Cost-recovery clauses - offsets to derivative assets (2)		6		17
Transmission and delivery storm reserve		47		56
Accumulated reserve - cost of removal (5)		545		547
Other		7		7
Total regulatory liabilities		708		745
Less: Current portion		124		154
Long-term regulatory liabilities	$	584	$	591

(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 liability related to derivative assets, refund occurs in the year following the settlement of the derivative position.

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(3) This asset is related to costs associated with environmental remediation primarily at MGP 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 based on a settlement agreement approved by the FPSC.

(4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.

(5) 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.

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. Prior to the Merger, TEC was included in the filing of a consolidated federal income tax return with TECO Energy 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 respective tax sharing agreements of TECO Energy and EUSHI. 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.

The IRS concluded its examination of TECO Energy’s 2015 consolidated federal income tax return in March 2017 with no changes required. The U.S. federal statute of limitations remains open for the year 2013 and forward. The short tax year ending June 30, 2016 is 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.

TEC’s effective tax rates for the three months ended March 31, 2017 and 2016 were 38.46% and 36.70%, respectively. The increase in the three-month effective tax rate in 2017 versus the same period in 2016 is primarily due to a decreased AFUDC-equity tax benefit. TEC’s effective tax rates for the three months ended March 31, 2017 and 2016 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity.

As of March 31, 2017, the amount of unrecognized tax benefits was $7 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. 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 March 31, 2017, if recognized, $7 million of the unrecognized tax benefits would reduce TEC’s effective tax rate.

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. The following table presents detail related to TECO Energy’s periodic expense for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP.

TECO Energy Pension Expense
(millions)	Pension Benefits							Other Postretirement Benefits
Three months ended March 31,	2017				2016			2017			2016
Components of net periodic benefit expense
Service cost	$	5			$	5		$	1		$	1
Interest cost		7				8			2			2
Expected return on assets		(12	)			(11	)		0			0
Amortization of:
Prior service (benefit) cost		0				0			(1	)		(1	)
Actuarial loss		4				3			0			0
Settlement cost		7		(1)		0			0			0
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	11			$	5		$	2		$	2

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(1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

TEC’s portion of the net pension expense for the three months ended March 31, 2017 and 2016, respectively, was $3 million and $3 million for pension benefits, and $1 million and $2 million for other postretirement benefits.  

For the January 1, 2017 measurement, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.160% for pension benefits under its qualified pension plan.  For the January 1, 2017 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.280%.

TECO Energy made contributions of $14 million and $5 million to its qualified pension plan in the three months ended March 31, 2017 and 2016, respectively. TEC’s portion of these contributions was $11 million and $4 million, respectively.

Included in the benefit expenses discussed above, for the three months ended March 31, 2017 and 2016, TEC reclassified $2 million and $2 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

	March 31, 2017						December 31, 2016
					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	$	175	$	1	$	325	$	40	$	1
3-year accounts    receivable facility (3)		150		101		0		150		130		0
Total	$	475	$	276	$	1	$	475	$	170	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2022.

(3) This 3-year facility matures March 23, 2018.

At March 31, 2017, 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 March 31, 2017 and December 31, 2016 was 1.72% and 1.49%, respectively.

Tampa Electric Company Credit Facility

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); (ii) includes a $50 million letter of credit facility; and (iii) made other technical changes.

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2017, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,308 million. At December 31, 2016, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,345 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data. 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 $57 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 measurements(see Note 11 for information regarding the fair value hierarchy).

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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. TEC believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously.

Tampa Electric Legal Proceeding

A suit has been filed against Tampa Electric alleging, among other things, wrongful death due to electrocution as a result of coming into contact with a downed power line in July 2016. Discovery is currently ongoing in the case. TEC 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 TEC’s results of operations, financial condition or cash flows.  

PGS Legal Proceeding

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 natural gas service.  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. No trial date is currently set. TEC 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 TEC’s results of operations, financial condition or cash flows.  

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2017, TEC has estimated its ultimate financial liability to be $30 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 are expected to be paid over many years.

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 currently assessed 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. See Note 3 for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this reserve.

Long-Term Commitments

TEC has commitments for purchased power and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. TEC also has other purchase obligations for long-term service agreements and capital projects.  In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from

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customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at March 31, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2017	$	11	$	6	$	52	$	515	$	584
2018		10		3		11		264		288
2019		0		2		12		186		200
2020		0		2		7		163		172
2021		0		2		7		132		141
Thereafter		0		38		24		1,157		1,219
Total future minimum payments	$	21	$	53	$	113	$	2,417	$	2,604

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 March 31, 2017, TEC was in compliance with all required financial covenants.

9. Segment Information

(millions)	Tampa									Tampa Electric
Three months ended March 31,	Electric		PGS		Eliminations					Company
2017
Revenues - external	$	442	$	111	$	0				$	553
Intracompany sales		0		1		(1	)				0
Total revenues		442		112		(1	)				553
Total interest charges		25		4		0					29
Net income	$	42	$	14	$	0				$	56
2016
Revenues - external	$	424	$	127	$	0				$	551
Intracompany sales		1		4		(5	)				0
Total revenues		425		131		(5	)				551
Total interest charges		24		4		0					28
Net income	$	50	$	13	$	0				$	63
Total assets at March 31, 2017	$	7,388	$	1,213	$	(496	)	(1	)	$	8,105
Total assets at December 31, 2016	$	7,357	$	1,191	$	(465	)	(1	)	$	8,083

(1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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 customers.

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.

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In November 2016, Tampa Electric and the other major electric IOUs in Florida signed a stipulation agreement approved by the FPSC calling for a one-year moratorium on hedging of natural gas purchases. The stipulation agreement called for the FPSC to oversee one or more workshops in 2017 to seek a cost-effective way to insure against rising gas prices.  In April 2017, the FPSC decided to hold a hearing in the fall of 2017 to consider whether hedging should resume or be discontinued altogether.

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). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of March 31, 2017, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at March 31, 2017 and December 31, 2016 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. There were $6 million and $17 million derivative assets as of March 31, 2017 and December 31, 2016, respectively. Derivative liabilities were zero as of March 31, 2017 and December 31, 2016. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at March 31, 2017 and December 31, 2016 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 Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at March 31, 2017, net pretax reductions in fuel costs of $6 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2017 and 2016, 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 months ended March 31, 2017 and 2016 is less than $1 million. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to November 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of March 31, 2017, are expected to settle during the 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2017		0		17
2018		0		7
Total		0		24

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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 March 31, 2017, 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 standardized master arrangements in the electric and gas industry. 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.  

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.  

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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 March 31, 2017
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	6	$	0	$	6
	As of December 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	17	$	0	$	17

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 March 31, 2017, 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 March 31, 2017 and December 31, 2016, the carrying value of TEC’s short-term debt was 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 of TEC’s short-term debt is determined using Level 2 measurements. See Note 7 for information regarding the fair value of long-term debt.

12. 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 $4 million and $13 million under these PPAs for the three months ended March 31, 2017 and 2016, 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.

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Item 2. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on TEC's current expectations and assumptions, and TEC does not undertake to update that information or any other information contained in this Managements Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions or legislation by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida economy; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost; natural gas demand; and the ability of TEC to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under "Risk Factors" in TEC’s Annual Report on Form 10-K for the year ended December 31, 2016.

Earnings Summary - Unaudited

		Three months ended March 31,
(millions)		2017			2016
Segment revenues
	Tampa Electric	$	442		$	425
	PGS		112			131
	Eliminations		(1	)		(5	)
		$	553		$	551
Net income
	Tampa Electric	$	42		$	50
	PGS		14			13
		$	56		$	63

Operating Results

Three Months Ended March 31, 2017

First quarter 2017 net income was $56 million, compared with $63 million in the first quarter of 2016.  First quarter 2017 results were impacted by mild weather and higher operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, partially offset by customer growth. See below for further detail.

Operating Company Results

All amounts included in the operating company discussions below are after tax, unless otherwise noted.

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Tampa Electric Company – Electric Division

Tampa Electric’s net income for the first quarter of 2017 was $42 million, compared with $50 million for the same period in 2016.  Results reflected higher operations and maintenance, depreciation and property tax expenses. First-quarter net income in 2017 included $1 million of AFUDC-equity, the allowed equity cost capitalized to construction costs, which decreased compared with $6 million in the same period in 2016 due to the completion of the Polk Power Station expansion in January 2017. Results for the quarter reflect a 2.1% higher number of customers compared to the same period in 2016.

Total degree days in Tampa Electric's service area in the first quarter of 2017 were 7% below normal and 8% below the 2016 period as a result of mild winter weather. Total net energy for load decreased 1.3% in the first quarter of 2017, compared with the same period in 2016. In the 2017 period, pretax base revenues were $16 million higher than in 2016, driven by approximately $20 million pre-tax from higher base rates as a result of the 2013 rate case settlement related to the addition of the Polk Power Station in January 2017. The quarter base revenues also increased as a result of customer growth partially offset by impacts from mild winter weather. 

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $6 million higher than in the 2016 quarter, reflecting higher costs to safely and reliably operate and maintain the transmission and distribution systems, and higher employee-benefit costs in 2017 compared to 2016.  Depreciation and amortization expense increased $4 million in 2017, as the Polk unit was placed in service in January 2017 and from normal additions to facilities to reliably serve customers. 

Tampa Electric’s regulated operating statistics for the three months ended March 31, 2017 and 2016 are as follows:

(millions, except customers and total degree days)	Operating Revenues								Kilowatt-hour sales
Three months ended March 31,	2017		2016			% Change			2017		2016		% Change
By Customer Type
Residential	$	198	$	217			(9	)		1,761		1,915		(8	)
Commercial		131		133			(2	)		1,431		1,388		3
Industrial		39		39			-			504		461		9
Other sales of electricity		37		40			(8	)		386		401		(4	)
Deferred and other revenues (1)		22		(19	)		216
Total energy sales		427		410			4			4,082		4,165		(2	)
Sales for resale		1		1			-			36		50		(28	)
Other operating revenue		14		14			-
Total revenues	$	442	$	425			4			4,118		4,215		(2	)
Customers at March 31, (thousands)		743		728			2
Retail net energy for load (kilowatt hours)										4,261		4,317		(1	)
Total degree days										553		602		(8	)
(1)     Primarily reflects the timing of clause recoveries.

Tampa Electric Company – Natural Gas Division

PGS reported net income of $14 million for the first quarter, compared with $13 million in the first quarter of 2016. Results reflect a 2.2% higher number of customers in the first quarter of 2017 compared to the first quarter of 2016. Residential and commercial therm sales decreased due to the very mild winter. Depreciation and amortization decreased $1 million due to new rates that reduce depreciation expense in accordance with an FPSC-approved 2016 depreciation study, partially offset by accelerated amortization of the regulatory asset associated with MGP environmental remediation costs (see Note 3 to the TEC Consolidated Condensed Financial Statements). First-quarter results in 2016 included $2 million of one-time compliance-related costs.  

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PGS’s regulated operating statistics for the three months ended March 31, 2017and 2016 are as follows:

(millions, except customers)	Operating Revenues							Therms
Three months ended March 31,	2017		2016		% Change			2017		2016		% Change
By Customer Type
Residential	$	42	$	50		(16	)		28		33		(15	)
Commercial		39		43		(9	)		134		141		(5	)
Industrial		4		3		33			87		83		5
Off system sales		10		13		(23	)		27		54		(50	)
Power generation		1		2		(50	)		181		191		(5	)
Other revenues		13		17		(24	)
Total	$	109	$	128		(15	)		457		502		(9	)
By Sales Type
System supply	$	61	$	75		(19	)		61		94		(35	)
Transportation		34		36		(6	)		396		408		(3	)
Other revenues		14		17		(18	)
Total	$	109	$	128		(15	)		457		502		(9	)
Customers at March 31, (thousands) (1)		372		364		2

(1)    The amount of 2016 customers reflects an updated customer count methodology due to the implementation of a new Customer Relationship Management and Billing System in the first quarter of 2017.

Other Income

For the three months ended March 31, 2017 and 2016, other income was $3 million and $7 million, respectively, and included AFUDC-equity of $1 million and $6 million, respectively. The decrease in AFUDC-equity is due to Tampa Electric’s Polk Power Station Units 2-5 combined cycle conversion being placed in service in January 2017.  

Income Taxes

The provisions for income taxes for the three months ended March 31, 2017 and 2016 were $35 million and $37 million, respectively. The provision for income taxes for the three months ended March 31, 2017 decreased due to lower pre-tax income.

Liquidity and Capital Resources

The table below sets forth the March 31, 2017 liquidity, cash balances, and amounts available under the TEC credit facilities.

(millions)
Credit facilities	$	475
Drawn amounts/letters of credit (1)		277
Available credit facilities		198
Cash and short-term investments		10
Total liquidity	$	208

(1) The increase from $171 million at December 31, 2016 is primarily attributable to the decrease in cash flows from operating activities. See below for further information.

Cash Impacts Related to Operating Activities

Cash flows from operating activities for the three months ended March 31, 2017 decreased compared to the same period in 2016. The decrease is primarily due to payments in 2017 related to significant December 2016 accruals for products and services; refunds to retail customers for prior period fuel clause over-recoveries; less 2017 fuel clause over-recoveries; and tax refunds in the first quarter of 2016.

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Covenants in Financing Agreements

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At March 31, 2017, TEC was in compliance with all applicable financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at March 31, 2017. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants

			Calculation
Instrument	Financial Covenant (1)	Requirement/Restriction	March 31, 2017
Credit facility (2)	Debt/capital	Cannot exceed 65%		46.7%
Accounts receivable credit facility (2)	Debt/capital	Cannot exceed 65%		46.7%

(1) As defined in each applicable instrument.

(2) See Note 6 to the TEC Consolidated Condensed Financial Statements for details of the credit facilities.

Credit Ratings of Senior Unsecured Debt at March 31, 2017

	S&P	Moody’s	Fitch
Credit ratings of senior unsecured debt	BBB+	A3	A-

On July 6, 2016, following the Merger with Emera, Moody’s downgraded the issuer rating and senior unsecured ratings of TEC to A3 from A2. This concluded the ratings review commenced by Moody’s on June 2, 2016. Moody’s described the ratings outlook as “Stable”.

On July 1, 2016, following the Merger with Emera, S&P affirmed the senior unsecured debt rating of TEC and maintained the ratings outlook at negative.

S&P, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus, all three credit rating agencies assign TEC’s senior unsecured debt investment-grade credit ratings.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 10 to the TEC Consolidated Condensed Financial Statements).

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Commitments and Contingencies

See Note 8 to the TEC Consolidated Condensed Financial Statements for information regarding TEC’s commitments and contingencies as of March 31, 2017.

Capital Investments

On January 16, 2017, the expansion of Tampa Electric’s Polk Power Station went into service. Therefore, construction work in progress decreased and plant increased by $524 million related to the Polk Power Station in January 2017.

The 2017 forecasted capital expenditures shown below are based on current estimates and assumptions. Actual capital expenditures could vary materially from these estimates due to changes in costs for materials or labor or changes in plans.

(millions)	Forecasted 2017
Tampa Electric (1)
Transmission	$	39
Distribution		164
Generation		116
New renewable generation		14
Facilities, equipment, vehicles and other		147
Tampa Electric total		480
PGS		141
Total	$	621

(1) Individual line items exclude AFUDC-debt and equity.

Fair Value Measurements

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying accounting standards for regulated operations, the changes in value of natural gas derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

The valuation methods used to determine fair value are described in Notes 7 and 11 to the TEC Consolidated Condensed Financial Statements. In addition, 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 and the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At March 31, 2017, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

TEC’s critical accounting policies relate to deferred income taxes, employee postretirement benefits and regulatory accounting. For further discussion of critical accounting policies and estimates, see TEC’s Annual Report on Form 10-K for the year ended December 31, 2016.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to settlements of natural gas swaps and the decrease in the average market price component of TEC’s outstanding natural gas swaps of approximately 4% from December 31, 2016 to March 31, 2017. TEC decreased the natural gas volume hedged as of March 31, 2017 as compared to December 31, 2016 by approximately 27%.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three-month period ended March 31, 2017:

Change in Fair Value of Derivatives (millions)

Net fair value of derivatives as of December 31, 2016	$	17
Additions and net changes in unrealized fair value of derivatives		(10	)
Realized net settlement of derivatives		(1	)
Net fair value of derivatives as of March 31, 2017	$	6

Roll-Forward of Derivative Net Assets (Liabilities) (millions)

Total derivative net assets (liabilities) as of December 31, 2016	$	17
Change in fair value of derivative net assets (liabilities):
Recorded as regulatory assets and liabilities or other comprehensive income		(10	)
Realized net settlement of derivatives		(1	)
Net fair value of derivatives as of March 31, 2017	$	6

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at March 31, 2017:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) (millions)	Current		Non-current		Total Fair Value
Source of fair value
Other external price sources (1)	$	6	$	0	$	6

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

For all unrealized derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

23

Item 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures. TEC’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TEC’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2017. Based on such evaluation, TEC’s principal financial officer and principal executive officer have concluded that, as of March 31, 2017, TEC’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. TEC has implemented a Customer Relationship Management and Billing System, developed by SAP, to replace certain of its legacy computer systems as a process improvement initiative. This system became operational in January 2017. In response, TEC has made appropriate changes to internal controls and procedures, as is expected with a major system implementation. There were no other changes in TEC’s internal controls over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TEC’s internal control over financial reporting that occurred during TEC’s last fiscal quarter that have materially affected, or is reasonably likely to materially affect, such controls.

24

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

From time to time, TEC is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on TEC’s results of operations, financial condition, or cash flows.

For a discussion of certain legal proceedings and environmental matters, including an update of previously disclosed legal proceedings and environmental matters, see Note 8 of the TEC Consolidated Condensed Financial Statements.

Item 6. EXHIBITS

Exhibits - See index on page 27.

25

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: May 11, 2017	By:	/s/ Gregory W. Blunden
		Gregory W. Blunden
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

26

INDEX TO EXHIBITS

Exhibit
No.	Description
3.1	Restated Articles of Incorporation of Tampa Electric Company, as amended on November 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.2	Bylaws of Tampa Electric Company, as amended effective February 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of Tampa Electric Company).	*
10.1	Fifth Amended and Restated Credit Agreement dated as of March 22, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.1, Form 8-K dated March 22, 2017 of Tampa Electric Company).	*
31.1	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

(1) This certification accompanies the Quarterly Report on Form 10-Q and is not filed as part of it.

* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and TEC were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

27

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Gordon L. Gillette, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 11, 2017	/s/  GORDON L. GILLETTE
		GORDON L. GILLETTE
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Gregory W. Blunden, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 11, 2017	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-32

Exhibit 32

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended March 31, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 11, 2017	/s/  GORDON L. GILLETTE
		GORDON L. GILLETTE
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	May 11, 2017	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-Q and shall not be considered filed as part of the Form 10-Q.

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 09, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Trading Symbol	ck0000096271
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

XML

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Property, plant and equipment
Utility plant, at original costs	$ 10,072	$ 10,019
Construction work in progress	262	892
Accumulated depreciation	(2,839)	(2,826)
Utility plant, net	7,233	7,193
Other property	11	10
Total property, plant and equipment, net	7,244	7,203
Current assets
Cash and cash equivalents	10	10
Receivables, less allowance for uncollectibles of $3 and $1 at March 31, 2017 and December 31, 2016, respectively	200	206
Due from affiliates	2	7
Inventories, at average cost
Derivative assets	6	15
Regulatory assets	29	28
Prepayments and other current assets	22	21
Total current assets	440	450
Deferred debits
Regulatory assets	390	393
Other	31	37
Total deferred debits	421	430
Total assets	8,105	8,083
Capitalization
Common stock	2,483	2,456
Accumulated other comprehensive loss	(3)	(3)
Retained earnings	303	311
Total capital	2,783	2,764
Long-term debt	2,163	2,163
Total capitalization	4,946	4,927
Current liabilities
Notes payable	276	170
Accounts payable	154	262
Due to affiliates	19	25
Customer deposits	141	146
Regulatory liabilities	124	154
Accrued interest	38	16
Accrued taxes	29	12
Other	10	11
Total current liabilities	791	796
Deferred credits
Deferred income taxes	1,425	1,407
Investment tax credits	22	11
Regulatory liabilities	584	591
Deferred credits and other liabilities	337	351
Total deferred credits	2,368	2,360
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	8,105	8,083
Fuel [Member]
Inventories, at average cost
Utility inventories	78	77
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	93	86
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	8,281	7,624
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 1,529	$ 1,503

XML

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Allowance for uncollectibles	$ 3	$ 1

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
Electric	$ 442	$ 424
Gas	111	127
Total revenues	553	551
Expenses
Fuel	131	115
Purchased power	7	14
Cost of natural gas sold	36	50
Operations and maintenance	128	121
Depreciation and amortization	85	81
Taxes, other than income	49	49
Total expenses	436	430
Income from operations	117	121
Other income
Allowance for equity funds used during construction	1	6
Other income, net	2	1
Total other income	3	7
Interest charges
Interest on long-term debt	28	29
Interest expense	2	1
Allowance for borrowed funds used during construction	(1)	(2)
Total interest charges	29	28
Income before provision for income taxes	91	100
Provision for income taxes	35	37
Net income	56	63
Comprehensive income	$ 56	$ 63

XML

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities
Net income	$ 56	$ 63
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	85	81
Deferred income taxes and investment tax credits	35	30
Allowance for equity funds used during construction	(1)	(6)
Deferred recovery clauses	(23)	27
Receivables, less allowance for uncollectibles	11	25
Inventories	(8)	(10)
Taxes accrued	16	82
Interest accrued	22	24
Accounts payable	(101)	(41)
Other	(16)	(7)
Cash flows from operating activities	76	268
Cash flows from investing activities
Capital expenditures	(143)	(151)
Cash flows used in investing activities	(143)	(151)
Cash flows from financing activities
Common stock	27	25
Net increase (decrease) in short-term debt	106	(61)
Dividends	(65)	(62)
Other financing activities	(1)	0
Cash flows from (used in) financing activities	67	(98)
Net increase in cash and cash equivalents	0	19
Cash and cash equivalents at beginning of period	10	9
Cash and cash equivalents at end of period	10	28
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (12)	$ (5)

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TEC’s 2016 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

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.

Intercompany balances and transactions within the divisions 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 March 31, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended March 31, 2017 and 2016. The results of operations for the three months ended March 31, 2017 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2017.

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.

TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.

Revenues

As of March 31, 2017 and December 31, 2016, unbilled revenues of $56 million and $54 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 $26 million and $28 million for the three months ended March 31, 2017 and 2016, respectively.

XML

New Accounting Pronouncements

3 Months Ended

Mar. 31, 2017

Accounting Changes And Error Corrections [Abstract]

New Accounting Pronouncements

2. New Accounting Pronouncements

Future Accounting Pronouncements

TEC considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the FASB.  The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in TEC’s 2016 Annual Report on Form 10-K, with the exception of the items noted below.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, which has been codified as ASC Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. TEC will adopt this guidance effective January 1, 2018. 

While TEC does not currently expect the impact to be significant, TEC is continuing to evaluate the impact of the adoption of this standard on its consolidated financial statements. TEC implemented a project plan in 2016, and is in the process of reviewing material revenue streams in line with this plan, with conclusions on the impact on the streams expected in the second and third quarter of 2017. In addition, TEC is evaluating the available adoption methods, the impact of collectibility risk, and disclosure requirements. In the first quarter of 2017, TEC has concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. TEC is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

XML

Regulatory

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

Regulatory

3. Regulatory

Base Rates-Tampa Electric

Tampa Electric’s results reflect a stipulation and settlement agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provides for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software beginning on January 1, 2013.

Storm Damage Cost Recovery-Tampa Electric

As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $9 million of storm costs in 2016. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surcharge to customers during the five-month period ended December 31, 2017. Subsequent communications with FPSC staff and signatories to the 2013 stipulation and settlement agreement resulted in a conclusion to withdraw the petition, apply the storm costs to the transmission and delivery storm reserve and seek recovery of storm costs once the reserve is fully depleted. See the table below for the regulatory liability.

Base Rates-PGS

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and decrease the bottom of the ROE range from 9.75% to 9.25%. The new bottom of the ROE range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020. The top of the ROE range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. On February 7, 2017, the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement.

As part of the settlement, PGS and OPC agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million will be amortized over a two-year recovery period beginning in 2016. In 2016, PGS recorded $16 million of this amortization expense. This additional amortization expense in 2016 was offset by the decrease in depreciation expense as discussed above with no impact to 2016 earnings. For the three months ended March 31, 2017, PGS recorded $1 million of amortization expense.  

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: 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)	March 31, 2017		December 31, 2016
Regulatory assets:
Regulatory tax asset (1)	$	85	$	86
Cost-recovery clauses - deferred balances (2)		10		8
Environmental remediation (3)		35		37
Postretirement benefits (4)		269		272
Other		20		18
Total regulatory assets		419		421
Less: Current portion		29		28
Long-term regulatory assets	$	390	$	393
Regulatory liabilities:
Regulatory tax liability	$	12	$	6
Cost-recovery clauses - deferred balances (2)		91		112
Cost-recovery clauses - offsets to derivative assets (2)		6		17
Transmission and delivery storm reserve		47		56
Accumulated reserve - cost of removal (5)		545		547
Other		7		7
Total regulatory liabilities		708		745
Less: Current portion		124		154
Long-term regulatory liabilities	$	584	$	591

(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 liability related to derivative assets, refund occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at MGP 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 based on a settlement agreement approved by the FPSC.

(4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.

(5) 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.

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Income Taxes

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

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. Prior to the Merger, TEC was included in the filing of a consolidated federal income tax return with TECO Energy 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 respective tax sharing agreements of TECO Energy and EUSHI. 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.

The IRS concluded its examination of TECO Energy’s 2015 consolidated federal income tax return in March 2017 with no changes required. The U.S. federal statute of limitations remains open for the year 2013 and forward. The short tax year ending June 30, 2016 is 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.

TEC’s effective tax rates for the three months ended March 31, 2017 and 2016 were 38.46% and 36.70%, respectively. The increase in the three-month effective tax rate in 2017 versus the same period in 2016 is primarily due to a decreased AFUDC-equity tax benefit. TEC’s effective tax rates for the three months ended March 31, 2017 and 2016 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity.

As of March 31, 2017, the amount of unrecognized tax benefits was $7 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. 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 March 31, 2017, if recognized, $7 million of the unrecognized tax benefits would reduce TEC’s effective tax rate.

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Employee Postretirement Benefits

3 Months Ended

Mar. 31, 2017

Compensation And Retirement Disclosure [Abstract]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. The following table presents detail related to TECO Energy’s periodic expense for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP.

TECO Energy Pension Expense
(millions)	Pension Benefits							Other Postretirement Benefits
Three months ended March 31,	2017				2016			2017			2016
Components of net periodic benefit expense
Service cost	$	5			$	5		$	1		$	1
Interest cost		7				8			2			2
Expected return on assets		(12	)			(11	)		0			0
Amortization of:
Prior service (benefit) cost		0				0			(1	)		(1	)
Actuarial loss		4				3			0			0
Settlement cost		7		(1)		0			0			0
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	11			$	5		$	2		$	2

(1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

TEC’s portion of the net pension expense for the three months ended March 31, 2017 and 2016, respectively, was $3 million and $3 million for pension benefits, and $1 million and $2 million for other postretirement benefits.  

For the January 1, 2017 measurement, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.160% for pension benefits under its qualified pension plan.  For the January 1, 2017 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.280%.

TECO Energy made contributions of $14 million and $5 million to its qualified pension plan in the three months ended March 31, 2017 and 2016, respectively. TEC’s portion of these contributions was $11 million and $4 million, respectively.

Included in the benefit expenses discussed above, for the three months ended March 31, 2017 and 2016, TEC reclassified $2 million and $2 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

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Short-Term Debt

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Short-Term Debt

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

	March 31, 2017						December 31, 2016
					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	$	175	$	1	$	325	$	40	$	1
3-year accounts    receivable facility (3)		150		101		0		150		130		0
Total	$	475	$	276	$	1	$	475	$	170	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2022.

(3) This 3-year facility matures March 23, 2018.

At March 31, 2017, 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 March 31, 2017 and December 31, 2016 was 1.72% and 1.49%, respectively.

Tampa Electric Company Credit Facility

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); (ii) includes a $50 million letter of credit facility; and (iii) made other technical changes.

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Long-Term Debt

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2017, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,308 million. At December 31, 2016, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,345 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data. 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 $57 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 measurements(see Note 11 for information regarding the fair value hierarchy).

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments And Contingencies Disclosure [Abstract]

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. TEC believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously.

Tampa Electric Legal Proceeding

A suit has been filed against Tampa Electric alleging, among other things, wrongful death due to electrocution as a result of coming into contact with a downed power line in July 2016. Discovery is currently ongoing in the case. TEC 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 TEC’s results of operations, financial condition or cash flows.  

PGS Legal Proceeding

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 natural gas service.  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. No trial date is currently set. TEC 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 TEC’s results of operations, financial condition or cash flows.  

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2017, TEC has estimated its ultimate financial liability to be $30 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 are expected to be paid over many years.

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 currently assessed 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. See Note 3 for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this reserve.

Long-Term Commitments

TEC has commitments for purchased power and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. TEC also has other purchase obligations for long-term service agreements and capital projects.  In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at March 31, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2017	$	11	$	6	$	52	$	515	$	584
2018		10		3		11		264		288
2019		0		2		12		186		200
2020		0		2		7		163		172
2021		0		2		7		132		141
Thereafter		0		38		24		1,157		1,219
Total future minimum payments	$	21	$	53	$	113	$	2,417	$	2,604

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 March 31, 2017, TEC was in compliance with all required financial covenants.

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Segment Information

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Segment Information

9. Segment Information

(millions)	Tampa									Tampa Electric
Three months ended March 31,	Electric		PGS		Eliminations					Company
2017
Revenues - external	$	442	$	111	$	0				$	553
Intracompany sales		0		1		(1	)				0
Total revenues		442		112		(1	)				553
Total interest charges		25		4		0					29
Net income	$	42	$	14	$	0				$	56
2016
Revenues - external	$	424	$	127	$	0				$	551
Intracompany sales		1		4		(5	)				0
Total revenues		425		131		(5	)				551
Total interest charges		24		4		0					28
Net income	$	50	$	13	$	0				$	63
Total assets at March 31, 2017	$	7,388	$	1,213	$	(496	)	(1	)	$	8,105
Total assets at December 31, 2016	$	7,357	$	1,191	$	(465	)	(1	)	$	8,083

(1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

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 customers.

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.

In November 2016, Tampa Electric and the other major electric IOUs in Florida signed a stipulation agreement approved by the FPSC calling for a one-year moratorium on hedging of natural gas purchases. The stipulation agreement called for the FPSC to oversee one or more workshops in 2017 to seek a cost-effective way to insure against rising gas prices.  In April 2017, the FPSC decided to hold a hearing in the fall of 2017 to consider whether hedging should resume or be discontinued altogether.

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). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of March 31, 2017, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at March 31, 2017 and December 31, 2016 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. There were $6 million and $17 million derivative assets as of March 31, 2017 and December 31, 2016, respectively. Derivative liabilities were zero as of March 31, 2017 and December 31, 2016. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at March 31, 2017 and December 31, 2016 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 Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at March 31, 2017, net pretax reductions in fuel costs of $6 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2017 and 2016, 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 months ended March 31, 2017 and 2016 is less than $1 million. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to November 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of March 31, 2017, are expected to settle during the 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2017		0		17
2018		0		7
Total		0		24

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 March 31, 2017, 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 standardized master arrangements in the electric and gas industry. 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.  

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

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 March 31, 2017
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	6	$	0	$	6
	As of December 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	17	$	0	$	17

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 March 31, 2017, 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 March 31, 2017 and December 31, 2016, the carrying value of TEC’s short-term debt was 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 of TEC’s short-term debt is determined using Level 2 measurements. See Note 7 for information regarding the fair value of long-term debt.

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Variable Interest Entities

3 Months Ended

Mar. 31, 2017

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Variable Interest Entities

12. 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 $4 million and $13 million under these PPAs for the three months ended March 31, 2017 and 2016, 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.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

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.

Intercompany balances and transactions within the divisions 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 March 31, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended March 31, 2017 and 2016. The results of operations for the three months ended March 31, 2017 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2017.

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.

TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.

Revenues

Revenues

As of March 31, 2017 and December 31, 2016, unbilled revenues of $56 million and $54 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

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 $26 million and $28 million for the three months ended March 31, 2017 and 2016, respectively.

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Regulatory (Tables)

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

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)	March 31, 2017		December 31, 2016
Regulatory assets:
Regulatory tax asset (1)	$	85	$	86
Cost-recovery clauses - deferred balances (2)		10		8
Environmental remediation (3)		35		37
Postretirement benefits (4)		269		272
Other		20		18
Total regulatory assets		419		421
Less: Current portion		29		28
Long-term regulatory assets	$	390	$	393
Regulatory liabilities:
Regulatory tax liability	$	12	$	6
Cost-recovery clauses - deferred balances (2)		91		112
Cost-recovery clauses - offsets to derivative assets (2)		6		17
Transmission and delivery storm reserve		47		56
Accumulated reserve - cost of removal (5)		545		547
Other		7		7
Total regulatory liabilities		708		745
Less: Current portion		124		154
Long-term regulatory liabilities	$	584	$	591

(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 liability related to derivative assets, refund occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at MGP 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 based on a settlement agreement approved by the FPSC.

(4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.

(5) 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.

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Employee Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2017

Compensation And Retirement Disclosure [Abstract]

Schedule of Net Periodic Benefit Cost

The following table presents detail related to TECO Energy’s periodic expense for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP.

TECO Energy Pension Expense
(millions)	Pension Benefits							Other Postretirement Benefits
Three months ended March 31,	2017				2016			2017			2016
Components of net periodic benefit expense
Service cost	$	5			$	5		$	1		$	1
Interest cost		7				8			2			2
Expected return on assets		(12	)			(11	)		0			0
Amortization of:
Prior service (benefit) cost		0				0			(1	)		(1	)
Actuarial loss		4				3			0			0
Settlement cost		7		(1)		0			0			0
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	11			$	5		$	2		$	2

(1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

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Short-Term Debt (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Short-Term Debt Credit Facilities and Related Borrowings

Details of the credit facilities and related borrowings are presented in the following table:

	March 31, 2017						December 31, 2016
					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	$	175	$	1	$	325	$	40	$	1
3-year accounts    receivable facility (3)		150		101		0		150		130		0
Total	$	475	$	276	$	1	$	475	$	170	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2022.

(3) This 3-year facility matures March 23, 2018.

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2017

Commitments And Contingencies Disclosure [Abstract]

Schedule of Long-term Commitments

The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at March 31, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2017	$	11	$	6	$	52	$	515	$	584
2018		10		3		11		264		288
2019		0		2		12		186		200
2020		0		2		7		163		172
2021		0		2		7		132		141
Thereafter		0		38		24		1,157		1,219
Total future minimum payments	$	21	$	53	$	113	$	2,417	$	2,604

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Information

(millions)	Tampa									Tampa Electric
Three months ended March 31,	Electric		PGS		Eliminations					Company
2017
Revenues - external	$	442	$	111	$	0				$	553
Intracompany sales		0		1		(1	)				0
Total revenues		442		112		(1	)				553
Total interest charges		25		4		0					29
Net income	$	42	$	14	$	0				$	56
2016
Revenues - external	$	424	$	127	$	0				$	551
Intracompany sales		1		4		(5	)				0
Total revenues		425		131		(5	)				551
Total interest charges		24		4		0					28
Net income	$	50	$	13	$	0				$	63
Total assets at March 31, 2017	$	7,388	$	1,213	$	(496	)	(1	)	$	8,105
Total assets at December 31, 2016	$	7,357	$	1,191	$	(465	)	(1	)	$	8,083

(1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Volumes Expected to Settle

The following table presents TEC’s derivative volumes that, as of March 31, 2017, are expected to settle during the 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2017		0		17
2018		0		7
Total		0		24

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Schedule of Recurring Fair Value Measurements

Recurring Derivative Fair Value Measures
	As of March 31, 2017
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	6	$	0	$	6
	As of December 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	17	$	0	$	17

XML

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Accounting Policies [Abstract]
Unbilled revenues	$ 56		$ 54
Franchise fees and gross receipts taxes	$ 26	$ 28

XML

Regulatory - Additional Information (Detail) - USD ($)			3 Months Ended	12 Months Ended
	Dec. 15, 2016	Jun. 28, 2016	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2013
Public Utilities General Disclosures [Line Items]
Percentage of ROE			10.25%
Return on equity range			Range of plus or minus 1%
Potential increase in ROE			10.50%
Allowed equity in the capital structure					54.00%
Storm costs incurred			$ 9,000,000
Regulatory assets			$ 419,000,000	$ 421,000,000
PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Reduction in annual depreciation expense	$ 16,000,000
Date new bottom of return on equity range will remain in effect			Dec. 31, 2020
Settlement agreement date			February 7, 2017
Regulatory assets			$ 32,000,000
Regulatory asset amortization beginning period			2016
Regulatory asset amortization ending period			2020
Amortization expenses			$ 1,000,000	$ 16,000,000
PGS and OPC [Member] | Maximum [Member]
Public Utilities General Disclosures [Line Items]
Decrease bottom return on equity		9.75%
PGS and OPC [Member] | Minimum [Member]
Public Utilities General Disclosures [Line Items]
Amortization period of Regulatory Asset			2 years
Decrease bottom return on equity		9.25%
Litigation settlement, amount			$ 21,000,000
PGS [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE		10.75%
PGS [Member] | Maximum [Member]
Public Utilities General Disclosures [Line Items]
Return on equity		11.75%
November 1, 2013 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge			58,000,000
November 1, 2014 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge			8,000,000
November 1, 2015 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge			5,000,000
January 16, 2017 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge			$ 110,000,000
Condition One [Member]
Public Utilities General Disclosures [Line Items]
ROE upper range limit			11.25%
ROE lower range limit			9.25%
Condition Two [Member]
Public Utilities General Disclosures [Line Items]
ROE upper range limit			11.50%
ROE lower range limit			9.50%
Computer Software [Member]
Public Utilities General Disclosures [Line Items]
Amortization period of Regulatory Asset			15 years

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Regulatory assets:
Regulatory assets	$ 419	$ 421
Less: Current portion	29	28
Long-term regulatory assets	390	393
Regulatory liabilities:
Regulatory liabilities	708	745
Less: Current portion	124	154
Long-term regulatory liabilities	584	591
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	85	86
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	10	8
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	35	37
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	269	272
Other [Member]
Regulatory assets:
Regulatory assets	20	18
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	12	6
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory liabilities:
Regulatory liabilities	91	112
Cost-Recovery Clauses - Offsets to Derivative Assets [Member]
Regulatory liabilities:
Regulatory liabilities	6	17
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	47	56
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	545	547
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 7	$ 7

XML

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Taxes [Line Items]
Unrecognized tax benefits	$ 7
Tampa Electric Company [Member]
Income Taxes [Line Items]
Effective tax rate	38.46%	36.70%

XML

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017		Mar. 31, 2016
Pension Benefits [Member]
Amortization of:
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 3		$ 3
Other Postretirement Benefits [Member]
Amortization of:
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	1		2
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	5		5
Interest cost	7		8
Expected return on assets	(12)		(11)
Amortization of:
Prior service (benefit) cost	0		0
Actuarial loss	4		3
Settlement cost	7	[1]	0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	11		5
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1		1
Interest cost	2		2
Expected return on assets	0		0
Amortization of:
Prior service (benefit) cost	(1)		(1)
Actuarial loss	0		0
Settlement cost	0		0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 2		$ 2

[1] Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera.

XML

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions		3 Months Ended
	Jan. 01, 2017	Mar. 31, 2017	Mar. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Reclassification of regulatory assets to net income as part of periodic benefit expense		$ 2	$ 2
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.00%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net pension expense		3	3
Employer contributions		11	4
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.16%
Employer contributions		14	5
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net pension expense		$ 1	$ 2
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.28%

XML

Short-Term Debt - Credit Facilities and Related Borrowings (Detail) - USD ($)	Mar. 31, 2017	Mar. 22, 2017	Dec. 31, 2016
Line Of Credit Facility [Line Items]
Credit Facilities	$ 475,000,000	$ 50,000,000	$ 475,000,000
Borrowings Outstanding	276,000,000		170,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000		325,000,000
Borrowings Outstanding	175,000,000		40,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000		150,000,000
Borrowings Outstanding	101,000,000		130,000,000
Letters of Credit Outstanding	$ 0		$ 0

XML

Short-Term Debt - Credit Facilities and Related Borrowings (Parenthetical) (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2022	Mar. 22, 2022
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018

XML

Short-Term Debt - Additional Information (Detail) - USD ($)		3 Months Ended
	Mar. 22, 2017	Mar. 31, 2017	Dec. 31, 2016
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.72%	1.49%
Line of credit facility maximum borrowing capacity	$ 50,000,000	$ 475,000,000	$ 475,000,000
Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity	$ 325,000,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.125%
Minimum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date	Dec. 17, 2018
Maximum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.30%
Maximum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date	Mar. 22, 2022

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Debt Instrument [Line Items]
Long-term debt, carrying amount	$ 2,163	$ 2,163	$ 2,163
Estimated fair value	2,308		$ 2,345
Level 1 [Member]
Debt Instrument [Line Items]
Fair value of debt securities	$ 57

XML

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Mar. 31, 2017 USD ($)
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 30

XML

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Mar. 31, 2017 USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2017	$ 11
Future Minimum Purchased Power Payments Due, 2018	10
Future Minimum Purchased Power Payments Due, 2019	0
Future Minimum Purchased Power Payments Due, 2020	0
Future Minimum Purchased Power Payments Due, 2021	0
Future Minimum Purchased Power Payments Due, Thereafter	0
Total future minimum purchased power payments due	21
Future Minimum Operating Leases Payments Due, 2017	6
Future Minimum Operating Leases Payments Due, 2018	3
Future Minimum Operating Leases Payments Due, 2019	2
Future Minimum Operating Leases Payments Due, 2020	2
Future Minimum Operating Leases Payments Due, 2021	2
Future Minimum Operating Leases Payments Due, Thereafter	38
Total future minimum operating leases payments due	53
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2017	52
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	11
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2019	12
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2020	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2021	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	24
Total future minimum long-term service agreements/capital projects payments due	113
Future Minimum Clause Recoverable Commitments Payments Due, 2017	515
Future Minimum Clause Recoverable Commitments Payments Due, 2018	264
Future Minimum Clause Recoverable Commitments Payments Due, 2019	186
Future Minimum Clause Recoverable Commitments Payments Due, 2020	163
Future Minimum Clause Recoverable Commitments Payments Due, 2021	132
Future Minimum Clause Recoverable Commitments Payments Due, Thereafter	1,157
Total future minimum clause recoverable commitments payments due	2,417
Future Minimum Payments Due, 2017	584
Future Minimum Payments Due, 2018	288
Future Minimum Payments Due, 2019	200
Future Minimum Payments Due, 2020	172
Future Minimum Payments Due, 2021	141
Future Minimum Payments Due, Thereafter	1,219
Total future minimum payments	$ 2,604

XML

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total revenues	$ 553	$ 551
Total interest charges	29	28
Net income	56	63
Total assets	8,105		$ 8,083
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	553	551
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(1)	(5)
Total interest charges	0	0
Net income	0	0
Total assets	(496)		(465)
Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0
Eliminations [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	(1)	(5)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	442	425
Total interest charges	25	24
Net income	42	50
Total assets	7,388		7,357
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	442	424
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	1
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	112	131
Total interest charges	4	4
Net income	14	13
Total assets	1,213		$ 1,191
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	111	127
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 1	$ 4

XML

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Derivative [Line Items]
Derivative assets	$ 6,000,000		$ 17,000,000
Derivative liabilities	0		0
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	$ 6,000,000
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Nov. 30, 2018
Maximum [Member]
Derivative [Line Items]
Gain on cash flow hedges	$ 1,000,000	$ 1,000,000

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Mar. 31, 2017 MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	24,000,000
Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	17,000,000
Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,000,000

XML

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	$ 6	$ 17
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	6	17
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	6	17
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	$ 0	$ 0

XML

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 6	$ 17
Derivative liabilities	0	$ 0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	$ 0

XML

Variable Interest Entities - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) MW	Mar. 31, 2016 USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 7	$ 14
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 4	$ 13
Minimum [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