Tampa Electric 10-Q 2017 Q3 Quarterly report

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 September 30, 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 its 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 registrant was 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 November 8, 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)
kWac	kilowatt on an alternating current basis
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)

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Term	Meaning
MWH	megawatt-hour(s)
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	September 30,			December 31,
(millions)	2017			2016
Property, plant and equipment
Utility plant
Electric	$	8,444		$	7,624
Gas		1,580			1,503
Construction work in progress		271			892
Utility plant, at original costs		10,295			10,019
Accumulated depreciation		(2,967	)		(2,826	)
Utility plant, net		7,328			7,193
Other property		11			10
Total property, plant and equipment, net		7,339			7,203
Current assets
Cash and cash equivalents		18			10
Receivables, less allowance for uncollectibles of $1 at both September 30, 2017 and December 31, 2016		283			206
Due from affiliates		2			7
Inventories, at average cost
Fuel		77			77
Materials and supplies		94			86
Derivative assets		0			15
Regulatory assets		38			28
Prepayments and other current assets		18			21
Total current assets		530			450
Deferred debits
Regulatory assets		397			393
Other		40			37
Total deferred debits		437			430
Total assets	$	8,306		$	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	September 30,			December 31,
(millions)	2017			2016
Capitalization
Common stock	$	2,554		$	2,456
Accumulated other comprehensive loss		(2	)		(3	)
Retained earnings		373			311
Total capital		2,925			2,764
Long-term debt		1,859			2,163
Total capitalization		4,784			4,927
Current liabilities
Long-term debt due within one year		304			0
Notes payable		255			170
Accounts payable		226			262
Due to affiliates		13			25
Customer deposits		131			146
Regulatory liabilities		65			154
Accrued interest		41			16
Accrued taxes		66			12
Other		10			11
Total current liabilities		1,111			796
Deferred credits
Deferred income taxes		1,539			1,407
Investment tax credits		22			11
Regulatory liabilities		516			591
Deferred credits and other liabilities		334			351
Total deferred credits		2,411			2,360
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	8,306		$	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 September 30,
(millions)	2017		2016
Revenues
Electric	$	597	$	586
Gas		96		103
Total revenues		693		689
Expenses
Fuel		158		173
Purchased power		21		39
Cost of natural gas sold		44		40
Operations and maintenance		127		134
Depreciation and amortization		89		83
Taxes, other than income		53		53
Total expenses		492		522
Income from operations		201		167
Other income
Allowance for equity funds used during construction		0		6
Other income, net		2		2
Total other income		2		8
Interest charges
Interest on long-term debt		27		28
Other interest		3		2
Allowance for borrowed funds used during construction		0		(4	)
Total interest charges		30		26
Income before provision for income taxes		173		149
Provision for income taxes		67		49
Net income	$	106	$	100
Other comprehensive income, net of tax
Gain on cash flow hedges		0		1
Total other comprehensive income, net of tax		0		1
Comprehensive income	$	106	$	101

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

	Nine months ended September 30,
(millions)	2017			2016
Revenues
Electric	$	1,581		$	1,509
Gas		309			330
Total revenues		1,890			1,839
Expenses
Fuel		454			426
Purchased power		36			81
Cost of natural gas sold		115			126
Operations and maintenance		386			388
Depreciation and amortization		262			245
Taxes, other than income		151			149
Total expenses		1,404			1,415
Income from operations		486			424
Other income
Allowance for equity funds used during construction		1			18
Other income, net		6			4
Total other income		7			22
Interest charges
Interest on long-term debt		83			85
Other interest		7			4
Allowance for borrowed funds used during construction		(1	)		(9	)
Total interest charges		89			80
Income before provision for income taxes		404			366
Provision for income taxes		156			127
Net income	$	248		$	239
Other comprehensive income, net of tax
Gain on cash flow hedges		1			1
Total other comprehensive income, net of tax		1			1
Comprehensive income	$	249		$	240

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended September 30,
(millions)	2017			2016
Cash flows from operating activities
Net income	$	248		$	239
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		262			245
Deferred income taxes and investment tax credits		151			70
Allowance for equity funds used during construction		(1	)		(18	)
Deferred recovery clauses		(73	)		54
Receivables, less allowance for uncollectibles		(70	)		(25	)
Inventories		(8	)		18
Taxes accrued		45			123
Interest accrued		25			23
Accounts payable		(20	)		19
Regulatory assets and liabilities		(67	)		(6	)
Other		(30	)		(40	)
Cash flows from operating activities		462			702
Cash flows from investing activities
Capital expenditures		(451	)		(518	)
Net proceeds from sale of assets		0			9
Cash flows used in investing activities		(451	)		(509	)
Cash flows from financing activities
Equity contributions		98			90
Repayment of long-term debt		0			(83	)
Net increase (decrease) in short-term debt		85			(12	)
Dividends		(185	)		(182	)
Other financing activities		(1	)		0
Cash flows used in financing activities		(3	)		(187	)
Net increase in cash and cash equivalents		8			6
Cash and cash equivalents at beginning of period		10			9
Cash and cash equivalents at end of period	$	18		$	15
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(25	)	$	(20	)

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s Annual Report on Form 10-K for the year ended December 31, 2016 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 September 30, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended September 30, 2017 and 2016. The results of operations for the three and nine months ended September 30, 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 September 30, 2017 and December 31, 2016, unbilled revenues of $71 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 $31 million and $86 million for the three and nine months ended September 30, 2017, respectively, and $33 million and $89 million for the three and nine months ended September 30, 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 Annual Report on Form 10-K for the year ended December 31, 2016, 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, codified as Accounting Standards Codification (ASC) Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect 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

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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, using the modified retrospective approach. 

TEC implemented a revenue recognition project plan in 2016. In the first quarter of 2017, TEC concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In the second quarter of 2017, TEC completed an analysis of material regulated revenue streams and collectibility risk and concluded that there will be no material changes on adoption of this standard. In the third quarter of 2017, TEC evaluated the disclosure requirements and determined that the disaggregation of revenue information required by the new standard will not have a significant impact on TEC’s information gathering processes and procedures as the revenue information required by the standard is consistent with historical revenue information gathered by TEC for financial reporting purposes. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC does not have any equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. TEC will apply the new disclosure requirements effective January 1, 2018 and does not expect a significant impact.

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 assets and 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. In the third quarter of 2017, TEC implemented a project plan and is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures. This includes evaluating the available practical expedients, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements. TEC continues to monitor FASB amendments to ASC Topic 842.

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 as property, plant and equipment under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC is a participant in the comprehensive retirement plans of TECO Energy and applies multiemployer accounting. This new guidance will not impact accounting for multiemployer plans, therefore it will not impact TEC’s financial statements.

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities which amends the hedge accounting recognition and presentation requirements in ASC 815.  This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach. TEC is currently evaluating the impact of the adoption of this standard on the consolidated financial statements and does not expect the impact to be significant.

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3. Regulatory

Tampa Electric Base Rates-2013 Agreement

Tampa Electric’s results reflect the 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 provided 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 provided 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.

Tampa Electric Base Rates-2017 Agreement

On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaces the existing 2013 base rate settlement agreement discussed above and extends it another four years through 2021. The FPSC approved the agreement on November 6, 2017.    

The amended agreement provides for solar base rate adjustments (SoBRAs) for TEC’s substantial investments in solar generation. It includes the following SoBRAs: $31 million for 150 MWs effective September 1, 2018, $51 million for 250 MWs effective January 1, 2019, $31 million for 150 MWs effective January 1, 2020, and an additional $10 million for 50 MWs effective on January 1, 2021. In order for each tranche of SoBRA to take effect, Tampa Electric must show they are cost-effective and each individual project has a cost cap of $1,500/kWac.  Additionally, in order to build the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1475/kWac. The agreement includes a sharing provision that allows Tampa Electric to retain 25% of any cost savings for projects below $1500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects over four years and will accrue AFUDC during construction.   

The agreement maintains Tampa Electric’s allowed regulatory ROE at 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, 2022, 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 remains at 54%. The agreement contains certain customer protections related to potential changes in federal tax policy. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are crossed is also included and Tampa Electric agrees to a five-year financial hedging moratorium for natural gas and no investments in gas reserves.  

Tampa Electric Storm Restoration Cost Recovery

Prior to the September 6, 2013 stipulation and settlement agreement, Tampa Electric was accruing $8 million annually to an FPSC-approved self-insured storm reserve. Effective November 1, 2013, Tampa Electric ceased accruing for this storm reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013.  As of December 31, 2016, the balance of the self-insured storm reserve was $56 million.

As a result of several named storms, including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $10 million of storm costs in 2016. In the first quarter of 2017, Tampa Electric applied the $10 million of storm costs to the storm reserve. This resulted in a storm reserve balance of $46 million as of March 31, 2017.  Tampa Electric was impacted by Hurricane Irma in the third quarter of 2017 and has currently estimated the total incurred incremental cost of restoration to be approximately $70 million, of which $60 million was charged to the storm reserve, $4 million was charged to O&M expense, and $6 million was charged to capital expenditures. At September 30, 2017, the amount of $60 million charged to the storm reserve exceeded the $46 million balance by $14 million, which is currently recorded as a regulatory asset on the balance sheet. Based on an FPSC order, if the charges to the storm reserve exceed the account balance, the excess is to be carried as a regulatory asset. Tampa Electric expects to petition the FPSC in early 2018 for recovery of the storm costs in excess of the reserve as well as replenish the balance in

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the reserve to the $56 million level that existed as of October 31, 2013 for a total of $70 million. See the Regulatory Assets and Liabilities table below.

PGS Base Rates

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 settlement agreement provided that the 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 and nine months ended September 30, 2017, PGS recorded amortization expense of $1 million and $4 million, respectively.  

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the FASB’s 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 restoration or the future removal of property.

Details of the regulatory assets and liabilities are presented in the following table:

Regulatory Assets and Liabilities
(millions)	September 30, 2017		December 31, 2016
Regulatory assets:
Regulatory tax asset (1)	$	83	$	86
Cost-recovery clauses - deferred balances (2)		7		8
Environmental remediation (3)		33		37
Postretirement benefits (4)		276		272
Storm reserve (5)		14		0
Other		22		18
Total regulatory assets		435		421
Less: Current portion		38		28
Long-term regulatory assets	$	397	$	393
Regulatory liabilities:
Regulatory tax liability	$	12	$	6
Cost-recovery clauses - deferred balances (2)		38		112
Cost-recovery clauses - offsets to derivative assets (2)		0		17
Storm reserve (5)		0		56
Accumulated reserve - cost of removal (6)		524		547
Other		7		7
Total regulatory liabilities		581		745
Less: Current portion		65		154
Long-term regulatory liabilities	$	516	$	591

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(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) See Tampa Electric Storm Restoration Cost Recovery above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered over a 12-month period.

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents 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 2014 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 September 30, 2017 and 2016 were 38.73% and 32.53%, respectively. TEC’s effective tax rates for the nine months ended September 30, 2017 and 2016 were 38.61% and 34.59%, respectively. The increase in the three-month and nine-month effective tax rates in 2017 versus the same period in 2016 is primarily due to lower AFUDC-equity, production deduction and R&D tax credit tax benefits. TEC’s effective tax rate for the nine months ended September 30, 2017 differs from the statutory rate principally due to state income taxes. TEC’s effective tax rate for the nine months ended September 30, 2016 differs from the statutory rate principally due to state income taxes offset by tax benefits related to AFUDC-equity, production deduction and R&D tax credits.

As of September 30, 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 and be recognized within the next twelve months due to the ongoing audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. TEC had $7 million of unrecognized tax benefits at September 30, 2017, that, if recognized, would reduce TEC’s effective tax rate.

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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 benefit cost 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 Benefit Cost
(millions)	Pension Benefits							Other Postretirement Benefits
Three months ended September 30,	2017				2016			2017			2016
Components of net periodic benefit cost
Service cost	$	5			$	5		$	0		$	1
Interest cost		8				7			2			2
Expected return on assets		(12	)			(12	)		0			0
Amortization of:
Prior service (benefit) cost		0				0			0			(1	)
Actuarial (gain) loss		4				5			(1	)		0
Net periodic benefit cost	$	5			$	5		$	1		$	2
Nine months ended September 30,
Components of net periodic benefit cost
Service cost	$	15			$	14		$	1		$	1
Interest cost		24				23			6			6
Expected return on assets		(36	)			(34	)		0			0
Amortization of:
Prior service (benefit) cost		0				0			0			(2	)
Actuarial (gain) loss		12				12			(2	)		0
Curtailment cost		0				1			0			0
Settlement cost		7		(1)		1			0			0
Net periodic benefit cost	$	22			$	17		$	5		$	5

(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 periodic benefit cost for the three months ended September 30, 2017 and 2016, respectively, was $3 million and $4 million for pension benefits, and $1 million and $2 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the nine months ended September 30, 2017 and 2016, respectively, was $10 million for each period for pension benefits, and $4 million and $5 million for other postretirement benefits.  

For 2017, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.16% 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 4.28%.

TECO Energy made contributions of $46 million and $37 million to its qualified pension plan in the nine months ended September 30, 2017 and 2016, respectively. TEC’s portion of these contributions was $36 million and $31 million, respectively.

Included in the benefit cost discussed above, for the three and nine months ended September 30, 2017, TEC reclassified $3 million and $8 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses from regulatory assets to net income, compared with $3 million and $8 million for the three and nine months ended September 30, 2016, respectively.

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6. Short-Term Debt

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

	September 30, 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	$	170	$	1	$	325	$	40	$	1
3-year accounts    receivable facility (3)		150		85		0		150		130		0
Total	$	475	$	255	$	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 September 30, 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 September 30, 2017 and December 31, 2016 was 2.07% and 1.49%, respectively.

Tampa Electric Company Credit Facilities

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) included a $50 million letter of credit facility; and (iii) made other technical changes.

On November 2, 2017, TEC entered into a 364-day, $300 million credit agreement with a maturity date of November 1, 2018.  See Note 13 for additional information.

7. Long-Term Debt

Fair Value of Long-Term Debt

At September 30, 2017, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,377 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 determined using Level 1 measurements was $56 million and $58 million at September 30, 2017 and December 31, 2016, respectively. The fair value of the remaining debt securities is determined using Level 2 measurements(see Note 11 for information regarding the fair value hierarchy).

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 final disposition of these proceedings will not have a material effect on its results of operations, cash flows or financial position.

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 September 30, 2017, TEC has estimated its ultimate financial liability to be $30 million, primarily at PGS. This amount

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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 liability.

Long-Term Commitments

TEC has commitments for purchased power and long-term leases, primarily for land, building space, vehicles, office equipment,  heavy equipment, other purchase obligations, 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 September 30, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2017	$	3	$	1	$	38	$	124	$	166
2018		10		3		173		282		468
2019		0		2		74		187		263
2020		0		2		7		163		172
2021		0		2		7		133		142
Thereafter		0		38		29		1,159		1,226
Total future minimum payments	$	13	$	48	$	328	$	2,048	$	2,437

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements and has certain restrictive covenants in specific agreements and debt instruments. At September 30, 2017, TEC was in compliance with all required financial covenants.

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9. Segment Information

(millions)	Tampa								Tampa Electric
Three months ended September 30,	Electric		PGS		Eliminations				Company
2017
Revenues - external	$	597	$	96	$	0			$	693
Intracompany sales		1		14		(15	)			0
Total revenues		598		110		(15	)			693
Total interest charges		26		4		0				30
Net income	$	98	$	8	$	0			$	106
2016
Revenues - external	$	586	$	103	$	0			$	689
Intracompany sales		0		1		(1	)			0
Total revenues		586		104		(1	)			689
Total interest charges		22		4		0				26
Net income	$	94	$	6	$	0			$	100
Nine months ended September 30,
2017
Revenues - external	$	1,581	$	309	$	0			$	1,890
Intracompany sales		2		17		(19	)			0
Total revenues		1,583		326		(19	)			1,890
Total interest charges		78		11		0				89
Net income	$	217	$	31	$	0			$	248
2016
Revenues - external	$	1,509	$	330	$	0			$	1,839
Intracompany sales		1		7		(8	)			0
Total revenues		1,510		337		(8	)			1,839
Total interest charges		69		11		0				80
Net income	$	213	$	26	$	0			$	239
Total assets at September 30, 2017	$	7,544	$	1,253	$	(491	)	(1)	$	8,306
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.

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.  In September 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement, which replaces the existing 2013 base rate settlement agreement and includes a provision for a five-year moratorium on hedging of natural gas purchases. The FPSC approved the agreement on November 6, 2017 (see Note 3).       

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

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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 September 30, 2017, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected.

The derivatives that are designated as cash flow hedges at September 30, 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 approximately zero derivative assets and liabilities as of September 30, 2017 and $17 million of derivative assets as of 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 at September 30, 2017 and December 31, 2016.

All of the derivative asset and liabilities at September 30, 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 September 30, 2017, there are no net pre-tax reductions in fuel costs that 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 and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 is $1 million or less for each period. 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. Due to low hedging volumes and low natural gas price volatility, TEC’s financial natural gas contracts resulted in zero derivative assets and liabilities as of September 30, 2017.  The following table presents TEC’s derivative volumes that, as of September 30, 2017, are expected to settle during the 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2017		0		3
2018		0		7
Total		0		10

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 September 30, 2017, substantially all of the counterparties with transaction amounts outstanding in

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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 a basis for considering assumptions that market participants would use in pricing an asset or liability, 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.

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.  

Recurring Derivative Fair Value Measures
	As of September 30, 2017
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	0	$	0	$	0
	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. As of September 30, 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 September 30, 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

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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

A VIE is an entity that a company has a controlling financial interest in, and that controlling interest is determined through means other than a majority voting interest. 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 $5 million and $13 million under these PPAs for the three and nine months ended September 30, 2017, respectively, and $19 million and $48 million for the three and nine months ended September 30, 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.

13. Subsequent Events

On November 2, 2017, TEC entered into a 364-day, $300 million credit agreement with a consortium of banks. The credit agreement has a maturity date of November 1, 2018; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin.  

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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 Management’s 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; economic conditions affecting the Florida economy; weather variations and customer energy usage patterns affecting sales and operating costs 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 September 30,						Nine months ended September 30,
(millions)		2017			2016			2017			2016
Segment revenues
	Tampa Electric	$	598		$	586		$	1,583		$	1,510
	PGS		110			104			326			337
	Eliminations		(15	)		(1	)		(19	)		(8	)
		$	693		$	689		$	1,890		$	1,839
Net income
	Tampa Electric	$	98		$	94		$	217		$	213
	PGS		8			6			31			26
		$	106		$	100		$	248		$	239

Operating Results

Three Months Ended September 30, 2017

Third quarter 2017 net income was $106 million, compared with $100 million in the third quarter of 2016.  Third quarter 2017 results were impacted by higher base rates at Tampa Electric that went into effect with the completion of the Polk Power Station expansion in January 2017 and Tampa Electric and PGS customer growth, partially offset by a reduction in revenue associated with Hurricane Irma, higher depreciation expense and lower AFUDC at Tampa Electric. See below for further detail.

Nine Months Ended September 30, 2017

Year-to-date net income through September 30, 2017 was $248 million, compared with $239 million in the 2016 period.  Year-to-date 2017 results were impacted by higher base rates at Tampa Electric that went into effect with the completion of the Polk Power Station expansion in January 2017, Tampa Electric and PGS customer growth, and lower depreciation expense at PGS, partially offset by a reduction in revenue associated with Hurricane Irma, higher depreciation expense and lower AFUDC at Tampa Electric. See below for further detail.

Operating Company Results

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

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the third quarter of 2017 was $98 million, compared with $94 million for the same period in 2016.  Results for the quarter reflected higher base revenue from higher base rates as a result of the Polk Power Station expansion in January 2017. Results reflected lower operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, and higher depreciation and property tax expenses. Third-quarter net income in 2017 included approximately zero of AFUDC-equity

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compared with $6 million in the same period in 2016 due to the completion of the Polk Power Station expansion in January 2017. Results reflect a 1.7% increase in number of customers at September 30, 2017 compared to September 30, 2016.

In September 2017, Tampa Electric was impacted by Hurricane Irma. Incremental restoration expenditures are estimated at approximately $70 million pre-tax, with $60 million pre-tax charged to the storm reserve, $4 million pre-tax charged to O&M expense and $6 million pre-tax charged to capital expenditures. As discussed in Note 3 to the TEC Consolidated Condensed Financial Statements, the storm reserve balance prior to Hurricane Irma was $46 million and therefore the difference of $14 million has been deferred in a regulatory asset for future recovery.  

Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in the third quarter of 2017 were 7% above normal and equal to the 2016 period, however total net energy for load decreased 0.9% in the third quarter of 2017, compared with the same period in 2016. This decrease was a result of lost sales due to outages associated with Hurricane Irma. Year-to-date, pre-tax base revenues were $34 million higher than in 2016, primarily driven by higher base rates as a result of the expansion of the Polk Power Station in January 2017.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $4 million lower than in the 2016 quarter, reflecting lower costs to operate and maintain the generation assets in 2017 compared to 2016.  Depreciation and amortization expense increased $5 million in the third quarter of 2017, as the Polk Power Station expansion was placed in service in January 2017 and from normal additions to facilities to reliably serve customers. 

Tampa Electric’s net income year-to-date 2017 was $217 million, compared with $213 million for the same period in 2016. Results reflected higher base revenues from higher base rates described above, higher depreciation expense, higher property tax expense, and the impacts of Hurricane Irma described above. Year-to-date net income in 2017 included $1 million of AFUDC-equity, which decreased compared to $18 million in the same period in 2016 due to the completion of the Polk Power Station expansion in January 2017. Results reflect a 1.7% increase in the number of customers at September 30, 2017 compared to September 30, 2016.

Total degree days in Tampa Electric's service area in the year-to-date period of 2017 were 6% above normal and 2% above the 2016 period as a result of warmer than normal spring weather offset by mild winter weather in the first quarter. Although year-to-date degree days were higher this year compared to the same period last year, the mix of heating and cooling degree days had an adverse effect on the residential sector's energy sales. The lack of heating degree days and heating appliance use as well as lost sales due to outages associated with Hurricane Irma resulted in residential sales lower than last year. In the non-residential sectors, which are not as sensitive to heating degree days, revenues were higher than in 2016. While total load was in-line with the amount in the same period in 2016, higher 2017 base rates were a result of the 2013 rate case settlement related to the expansion of the Polk Power Station in January 2017.

In the 2017 year-to-date period, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was slightly above the amount in 2016. Depreciation and amortization expense increased $14 million in 2017, as the Polk unit was placed in service in January 2017 and from normal additions to facilities to reliably serve customers. 

As discussed in TEC’s Quarterly Report on Form 10-Q for the period ended June 30, 2017, on June 29, 2017, a tragic accident occurred during work being conducted at Tampa Electric's Big Bend Power Station Unit Two, resulting in employee and contractor fatalities. Although the financial impact to Tampa Electric has not been fully determined, any such impact is expected to be substantially covered by insurance.

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Tampa Electric’s regulated operating statistics for the three and nine months ended September 30, 2017 and 2016 are as follows:

(millions, except customers and total degree days)	Operating Revenues								Kilowatt-hour sales
Three months ended September 30,	2017		2016			% Change			2017		2016		% Change
By Customer Type
Residential	$	316	$	331			(5	)		2,861		2,960		(3	)
Commercial		160		167			(4	)		1,792		1,814		(1	)
Industrial		40		42			(5	)		522		499		5
Other sales of electricity		46		48			(4	)		480		503		(5	)
Deferred and other revenues (1)		21		(18	)	nm
Total energy sales		583		570			2			5,655		5,776		(2	)
Sales for resale		1		2			(50	)		20		56		(64	)
Other operating revenue		14		14			0
Total revenues	$	598	$	586			2			5,675		5,832		(3	)
Customers at September 30, (thousands)		745		733			2
Retail net energy for load (kilowatt hours)										5,994		6,045		(1	)
Total degree days										1,761		1,768		(0	)
Nine months ended September 30,
By Customer Type
Residential	$	769	$	801			(4	)		6,916		7,116		(3	)
Commercial		440		448			(2	)		4,859		4,767		2
Industrial		119		120			(1	)		1,530		1,438		6
Other sales of electricity		123		131			(6	)		1,282		1,351		(5	)
Deferred and other revenues (1)		81		(35	)	nm
Total energy sales		1,532		1,465			5			14,587		14,672		(1	)
Sales for resale		7		4			75			204		130		57
Other operating revenue		44		41			7
Total revenues	$	1,583	$	1,510			5			14,791		14,802		(0	)
Customers at September 30, (thousands)		745		733			2
Retail net energy for load (kilowatt hours)										15,631		15,624		0
Total degree days										3,691		3,625		2
(1)     Primarily reflects the timing of environmental and fuel clause recoveries.
nm     Not meaningful

Tampa Electric Company – Natural Gas Division

PGS reported net income of $8 million for the third quarter, compared with $6 million in the 2016 third quarter. Results reflected a 2.6% increase in number of customers in the third quarter of 2017 and increased therm sales to residential and commercial customers. Third-quarter results reflected $1 million higher operations and maintenance expense, excluding all FPSC-approved cost-recovery clause expense, and $1 million lower depreciation and amortization expense in 2017.

PGS reported net income of $31 million for the 2017 year-to-date period, compared with $26 million in the 2016 period. These results reflected lower residential and commercial therm sales as a result of the very mild winter, however base revenue is flat due to customer growth. Year-to-date net income reflected a $1 million increase due to the replacement of cast iron bare steel and problematic plastic pipe and decreased depreciation and amortization expense of $4 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).  

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PGS’s regulated operating statistics for the three and nine months ended September 30, 2017 and 2016 are as follows:

(millions, except customers)	Operating Revenues							Therms
Three months ended September 30,	2017		2016		% Change			2017		2016		% Change
By Customer Type
Residential	$	28	$	26		8			12		11		9
Commercial		32		31		3			112		108		4
Industrial		4		3		33			77		80		(4	)
Off system sales		29		28		4			85		79		8
Power generation		1		2		(50	)		204		205		(0	)
Other revenues		13		11		18
Total	$	107	$	101		6			490		483		1
By Sales Type
System supply	$	64	$	61		5			103		96		7
Transportation		30		29		3			387		387		0
Other revenues		13		11		18
Total	$	107	$	101		6			490		483		1
Customers at September 30, (thousands) (1)		374		365		3
Nine months ended September 30,
By Customer Type
Residential	$	101	$	107		(6	)		56		58		(3	)
Commercial		106		108		(2	)		366		367		(0	)
Industrial		11		10		10			245		241		2
Off system sales		56		59		(5	)		159		206		(23	)
Power generation		4		4		0			578		585		(1	)
Other revenues		40		40		0
Total	$	318	$	328		(3	)		1,404		1,457		(4	)
By Sales Type
System supply	$	182	$	194		(6	)		233		283		(18	)
Transportation		96		94		2			1,171		1,174		(0	)
Other revenues		40		40		0
Total	$	318	$	328		(3	)		1,404		1,457		(4	)
Customers at September 30, (thousands) (1)		374		365		3

(1)    The number 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 third quarter 2017 and 2016, other income was $2 million and $8 million, respectively, and included AFUDC-equity of zero and $6 million, respectively. For year-to-date 2017 and 2016, other income was $7 million and $22 million, respectively, and included AFUDC-equity of $1 million and $18 million, respectively. The decrease in AFUDC-equity is due to Tampa Electric’s Polk Power Station expansion being placed in service in January 2017.  

Income Taxes

The provisions for income taxes for the 2017 and 2016 year-to-date periods were $156 million and $127 million, respectively. The provision for income taxes for the 2017 year-to-date period increased due to higher pre-tax income and lower tax benefits related to AFUDC-equity discussed above, the production deduction and R&D tax credits.

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Liquidity and Capital Resources

The table below sets forth the September 30, 2017 liquidity, cash balances, and amounts available under the TEC credit facilities.

(millions)
Credit facilities	$	475
Drawn amounts/letters of credit		256
Available credit facilities		219
Cash and short-term investments		18
Total liquidity	$	237

Available Cash and Liquidity

Cash needs for the remainder of 2017 and for 2018 will be impacted by the effects of Hurricane Irma and the increase in capital expenditures primarily related to solar projects. The total cost of storm restoration to Tampa Electric’s system due to Hurricane Irma is currently estimated at $70 million. The amount of capital investments related to solar projects during 2017 – 2021 is currently estimated at approximately $850 million. See Note 3 to the TEC Consolidated Condensed Financial Statements and the Capital Investments sectionbelow for additional information regarding these items.

TEC expects to rely on cash on hand, internally generated cash from operations, borrowings under its existing credit facilities and the November 2017 credit facility, long-term debt issues, and equity contributions from TECO Energy to fund its needs in 2017 and 2018. TEC intends to fund these expenditures so that Tampa Electric and PGS maintain their capital structures consistent with the existing regulatory arrangements. See Note 13 to the TEC Consolidated Condensed Financial Statements for information on TEC’s credit facility entered into on November 2, 2017.

Cash Impacts Related to Operating Activities

Cash flows from operating activities for the nine months ended September 30, 2017 were $462 million, a decrease of $240 million 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 in 2017 for fuel clause over-recoveries collected in 2016; lower fuel clause over-recoveries collected in 2017; and increased receivables due to delays resulting from Hurricane Irma.

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 September 30, 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 September 30, 2017. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants

				Calculation
Instrument	��	Financial Covenant (1)	Requirement/Restriction	September 30, 2017
Credit facility (2)		Debt/capital	Cannot exceed 65%		45.3%
Accounts receivable credit facility (2)		Debt/capital	Cannot exceed 65%		45.3%

(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 September 30, 2017

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

S&P and Moody’s 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- and for Moody’s is Baa3; thus, both credit rating agencies assign TEC’s senior unsecured debt investment-grade credit ratings.

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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).

Commitments and Contingencies

See Note 8 to the TEC Consolidated Condensed Financial Statements for information regarding TEC’s commitments and contingencies as of September 30, 2017.

Capital Investments

On January 16, 2017, the expansion of Tampa Electric’s Polk Power Station went into service, resulting in a $524 million decrease in construction work in progress and increase in utility plant.

The 2017 forecasted capital expenditures shown below are based on current estimates and assumptions. The 2017 forecasted amounts have been updated from TEC’s Annual Report on Form 10-K to reflect expected increases in capital costs primarily related to land and equipment purchases for solar projects. Tampa Electric expects to spend approximately $850 million during 2017 through 2021 related to the 600 MW solar project recoverable under the SOBRAs as discussed in Note 3 to the TEC Consolidated Condensed Financial Statements. Actual capital expenditures could vary materially from these estimates due to changes in schedule, costs for materials or labor or changes in plans.

(millions)	Forecasted 2017
Tampa Electric (1)
Transmission	$	41
Distribution		191
Generation		113
Renewable generation		194
Facilities, equipment, vehicles and other		65
Tampa Electric total		604
PGS		129
Total	$	733

(1) Line items exclude AFUDC-debt and equity.

Fair Value Measurements

All natural gas derivatives were entered into by TEC 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 September 30, 2017, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

Critical accounting policies and estimates have not materially changed in 2017. 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.

Change in Executive Officers

On November 6, 2017, Emera announced that Nancy Tower, the current Chief Corporate Development Officer for Emera, will become the President and Chief Executive Officer of TEC upon Gordon Gillette’s retirement on November 30, 2017.

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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 September 30, 2017. TEC decreased by 70% the natural gas volume hedged as of September 30, 2017 as compared to December 31, 2016.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine-month period ended September 30, 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		(14	)
Realized net settlement of derivatives		(3	)
Net fair value of derivatives as of September 30, 2017	$	0

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		(14	)
Realized net settlement of derivatives		(3	)
Net fair value of derivatives as of September 30, 2017	$	0

As of September 30, 2017, there was a minor amount of unrealized derivative contract net assets. 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.

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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 September 30, 2017. Based on such evaluation, TEC’s principal financial officer and principal executive officer have concluded that, as of September 30, 2017, TEC’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. There was no change 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 has materially affected, or is reasonably likely to materially affect, such controls.

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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. TEC believes the final disposition of these proceedings will not have a material effect on its results of operations, cash flows or financial position.

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

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). (P)	*
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	Credit Agreement dated as of November 2, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated November 2, 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.

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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: November 13, 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)

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