ck0000096271-10q_20180630.htm

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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.

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 August 7, 2018, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

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

Term		Meaning
ABS		asset-backed security
AFUDC		allowance for funds used during construction
AFUDC-debt		debt component of allowance for funds used during construction
AFUDC-equity		equity component of allowance for funds used during construction
AOCI		accumulated other comprehensive income
APBO		accumulated postretirement benefit obligation
ARO		asset retirement obligation
ASC		Accounting Standards Codification
BACT		Best Available Control Technology
CAD		Canadian dollars
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
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)
MWH		megawatt-hour(s)
NAESB		North American Energy Standards Board

Assets	June 30,			December 31,
(millions)	2018			2017
Property, plant and equipment
Utility plant
Electric	$	8,682		$	8,555
Gas		1,672			1,609
Construction work in progress		524			263
Utility plant, at original costs		10,878			10,427
Accumulated depreciation		(3,108	)		(2,994	)
Utility plant, net		7,770			7,433
Other property		12			11
Total property, plant and equipment, net		7,782			7,444

Current assets
Cash and cash equivalents		15			13
Receivables, less allowance for uncollectibles of $1 at June 30, 2018 and December 31, 2017		251			257
Due from affiliates		17			5
Inventories, at average cost
Fuel		48			60
Materials and supplies		97			90
Regulatory assets		45			77
Prepayments and other current assets		15			13
Total current assets		488			515

Deferred debits
Regulatory assets		347			356
Other		47			49
Total deferred debits		394			405
Total assets	$	8,664		$	8,364

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

Liabilities and Capitalization	June 30,			December 31,
(millions)	2018			2017
Capitalization
Common stock	$	2,860		$	2,645
Accumulated other comprehensive loss		(1	)		(2	)
Retained earnings		323			335
Total capital		3,182			2,978
Long-term debt		2,205			1,860
Total capitalization		5,387			4,838

Current liabilities
Long-term debt due within one year		0			304
Notes payable		375			305
Accounts payable		218			233
Due to affiliates		15			21
Customer deposits		131			131
Regulatory liabilities		61			58
Accrued interest		14			14
Accrued taxes		50			12
Other		17			44
Total current liabilities		881			1,122

Long-term liabilities
Deferred income taxes		855			825
Regulatory liabilities		1,205			1,227
Deferred credits and other liabilities		336			352
Total long-term liabilities		2,396			2,404

Commitments and Contingencies (see Note 8)

Total liabilities and capitalization	$	8,664		$	8,364

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

	Three months ended June 30,
(millions)	2018			2017
Revenues
Electric	$	509		$	542
Gas		110			102
Total revenues		619			644
Expenses
Fuel		133			165
Purchased power		14			8
Cost of natural gas sold		39			35
Operations and maintenance		162			131
Depreciation and amortization		89			88
Taxes, other than income		51			49
Total expenses		488			476
Income from operations		131			168
Other income
Allowance for equity funds used during construction		1			0
Other income, net		2			2
Total other income		3			2
Interest charges
Interest on long-term debt		27			28
Other interest		3			2
Allowance for borrowed funds used during construction		(1	)		0
Total interest charges		29			30
Income before provision for income taxes		105			140
Provision for income taxes		20			54
Net income		85		$	86
Other comprehensive income, net of tax
Gain on cash flow hedges		1			0
Total other comprehensive income, net of tax		1			0
Comprehensive income	$	86		$	86

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

	Six months ended June 30,
(millions)	2018			2017
Revenues
Electric	$	970		$	984
Gas		246			213
Total revenues		1,216			1,197
Expenses
Fuel		255			296
Purchased power		27			15
Cost of natural gas sold		94			71
Operations and maintenance		319			259
Depreciation and amortization		182			173
Taxes, other than income		103			98
Total expenses		980			912
Income from operations		236			285
Other income
Allowance for equity funds used during construction		1			1
Other income, net		4			4
Total other income		5			5
Interest charges
Interest on long-term debt		54			56
Other interest		6			4
Allowance for borrowed funds used during construction		(1	)		(1	)
Total interest charges		59			59
Income before provision for income taxes		182			231
Provision for income taxes		34			89
Net income	$	148		$	142
Other comprehensive income, net of tax
Gain on cash flow hedges		1			1
Total other comprehensive income, net of tax		1			1
Comprehensive income	$	149		$	143

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

	Six months ended June 30,
(millions)	2018			2017
Cash flows from operating activities
Net income	$	148		$	142
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		182			173
Deferred income taxes and investment tax credits		14			87
Deferred recovery clauses		(25	)		(52	)
Receivables, less allowance for uncollectibles		2			(23	)
Inventories		5			(16	)
Taxes accrued		28			27
Accounts payable		(37	)		(88	)
Regulatory assets and liabilities		54			(6	)
Other		(25	)		(16	)
Cash flows from operating activities		346			228
Cash flows used in investing activities
Capital expenditures		(510	)		(299	)
Cash flows used in investing activities		(510	)		(299	)
Cash flows from financing activities
Equity contributions from TECO Energy		215			58
Proceeds from long-term debt issuance		345			0
Repayment of long-term debt		(304	)		0
Net increase in short-term debt		70			128
Dividends to TECO Energy		(160	)		(109	)
Other financing activities		0			(1	)
Cash flows from financing activities		166			76
Net increase in cash and cash equivalents		2			5
Cash and cash equivalents at beginning of period		13			10
Cash and cash equivalents at end of period	$	15		$	15
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	18		$	(24	)

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

See TEC’s Annual Report on Form 10-K for the year ended December 31, 2017 for a complete discussion of accounting policies. The significant accounting policies for TEC include:

TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. 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 June 30, 2018 and December 31, 2017, and the results of operations and cash flows for the periods ended June 30, 2018 and 2017. The results of operations for the three and six months ended June 30, 2018 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2018.

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 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.

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWh delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes.

Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue.

Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $249 million and $229 million as of June 30, 2018 and December 31, 2017, respectively. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

As of June 30, 2018 and December 31, 2017, unbilled revenues of $80 million and $66 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

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 $28 million and $29 million for the three months ended June 30, 2018 and 2017, respectively, and $57 million and $54 million for the six months ended June 30, 2018 and 2017, respectively.

The new U.S. GAAP accounting policies that are applicable to and adopted by TEC in 2018 are described as follows:

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, the FASB issued Accounting Standard Update (ASU) No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The standard allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the U.S. Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income or loss. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted. TEC has early adopted the standard in June 2018 and elected to not reclassify tax effects resulting from the U.S. Tax Cuts and Jobs Act stranded in accumulated other comprehensive income to retained earnings as amounts were not material. TEC utilizes a portfolio approach in order to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released. There is no impact on TEC’s Condensed Consolidated Financial Statements for the period ended June 30, 2018 as a result of implementation of this standard.

On January 1, 2018, TEC adopted ASU 2014-09, Revenue from Contracts with Customers and all the related amendments, which created a new, principle-based revenue recognition framework. The standard has been codified as ASC Topic 606. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance requires additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

TEC adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to TEC’s opening retained earnings as of the adoption date or TEC’s Condensed Consolidated Income Statement for the three and six months ended June 30, 2018. The impact of the adoption of the new standard was immaterial to TEC’s net income and is expected to be immaterial on an ongoing basis.

On January 1, 2018, TEC adopted ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities and all the related amendments. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business. The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and is required to be applied prospectively. TEC adopted ASU 2017-01 effective January 1, 2018. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

TEC considers the applicability and impact of all ASUs 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, 2017, with updates noted below.

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. TEC will not early adopt the standard.

In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. TEC expects to make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. TEC expects to make this election.

The standard will affect TEC’s financial position by increasing the assets and liabilities recorded relating to its operating leases. However, the ultimate impact of the new standard on TEC’s financial statements and disclosures has not yet been fully determined. In 2017, TEC developed and began execution of a project plan which included holding training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements. Activities currently being executed include evaluating the available implementation alternatives, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements. TEC will implement additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. Significant updates to systems are not expected. TEC continues to monitor FASB amendments to ASC Topic 842.

On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaced the 2013 base rate settlement agreement and extended it four years through December 31, 2021. The FPSC approved the agreement on November 6, 2017.

The amended agreement provides for SoBRAs for TEC’s investments in solar generation. The solar investments are expected to go into service in tranches beginning in September 2018 through January 2021. In order for each tranche of SoBRAs to take effect, Tampa Electric must show that each tranche is cost-effective and each individual project has a cost cap of $1,500/kWac. Additionally, in order to receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects.

The amended agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law. Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. See “Tampa Electric Tax Reform and Storm Settlement” below for information regarding the impact of tax reform.

On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue requirements. A decision by the FPSC on the second SoBRA is anticipated to occur in October 2018.

As a result of Tampa Electric’s 2013 rate case settlement, 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. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million, of which $90 million was charged to the storm reserve, $3 million was charged to O&M expense and $9 million was charged to capital expenditures. At December 31, 2017, the amount of estimated costs charged to the storm reserve regulatory liability exceeded the balance in the storm reserve by $47 million, which was recorded as a regulatory asset on the balance sheet as allowed by an FPSC order. This regulatory asset amount was reduced in the second quarter of 2018 to reflect partial recovery as discussed in Tampa Electric Tax Reform and Storm Settlement below. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs in excess of the reserve and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below.

On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addresses both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) while keeping customer rates stable in 2018. Beginning on April 1, 2018, the agreement authorizes Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits. As a result, in the first quarter of 2018, Tampa Electric recorded O&M expense and a regulatory liability of $19 million in order to offset tax reform benefits in the first quarter due to the agreement allowing the netting of the recovery of storm costs with tax reform benefits. This deferral was recorded as a result of deferring the impact of the first quarter as the effective date of the agreement is April 1, 2018. Beginning on April 1, 2018, the regulatory liability is being amortized over the remainder of 2018 as a credit against the recognition of storm expense. Amortization of $5 million was recorded as a reduction to O&M expense in the second quarter of 2018. In the second quarter of 2018, Tampa Electric recorded O&M expense and a reduction of the storm reserve regulatory asset of approximately $35 million to reflect effective recovery of the storm costs due to the allowed netting of storm cost recovery with tax reform benefits. Tampa Electric’s final storm costs subject to netting and final impact of tax reform on Tampa Electric’s base rates pursuant to the 2017 agreement will be determined in separate regulatory proceedings. Any difference will be trued up and recovered from or returned to customers in 2019. Tampa Electric’s updated 2018 tax reform benefits is approximately $102 million, which is slightly higher than the revised recoverable storm costs. In addition, beginning in January 2019, Tampa Electric will reflect the impact of tax reform on its base rates. Tampa Electric filed testimony supporting the calculation of the tax benefits on May 31, 2018. Hearings on the tax reform impacts for all state utilities have been scheduled for late August 2018.

PGS’s base rates were established in May 2009. An updated settlement agreement was approved by the FPSC on February 7, 2017.

The PGS settlement does not contain a provision for tax reform. The FPSC approved that tax reform benefits should be applied to customers beginning on February 6, 2018 for utilities in Florida without an existing tax reform settlement provision, including PGS. As a result, PGS deferred the estimated tax reform benefits to customers and recorded O&M expense and a regulatory tax liability of $5 million for the period February 6 to June 30, 2018, which is subject to negotiations with the FPSC. PGS filed testimony supporting the calculation of the tax benefits on May 31, 2018. A hearing on the tax reform impact has been scheduled for late August 2018.

Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred or the advance recovery of expenditures for approved costs.

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

Regulatory Assets and Liabilities
(millions)	June 30, 2018		December 31, 2017
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	44	$	45
Cost-recovery clauses - deferred balances ⁽²⁾		22		13
Environmental remediation⁽³⁾		29		33
Postretirement benefits ⁽⁴⁾		263		272
Storm reserve ⁽⁵⁾		9		47
Other		25		23
Total regulatory assets		392		433
Less: Current portion		45		77
Long-term regulatory assets	$	347	$	356
Regulatory liabilities:
Regulatory tax liability⁽⁶⁾	$	719	$	730
Tax reform and storm agreement⁽⁷⁾		13		0
Cost-recovery clauses ⁽²⁾		17		32
Accumulated reserve - cost of removal⁽⁸⁾		512		518
Other		5		5
Total regulatory liabilities		1,266		1,285
Less: Current portion		61		58
Long-term regulatory liabilities	$	1,205	$	1,227

On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of tax reform changes affecting businesses, effective January 1, 2018 which provide a corporate federal tax rate reduction from 35% to 21%, 100% asset expensing, limitation of interest deduction, the repeal of section 199 domestic production deduction and the preservation of the existing normalization rules. The Act also provides that regulated electric and gas companies are exempt from the 100% asset expensing and interest expense deduction limitation. In accordance with U.S. GAAP, TEC was required to revalue its deferred income tax assets and liabilities based on the new 21% federal tax rate at the date of enactment. Additionally, under FPSC rules TEC was required to adjust deferred income tax assets and liabilities for changes in tax rates with a corresponding regulatory liability for the excess deferred taxes generated by the tax rate differential. See Note 3.

TEC continues to analyze certain aspects of the Act, including the uncertainty of the application of 100% asset expensing rules after September 27, 2017, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by TEC during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act. No measurement period adjustments have been recognized during the first half of 2018.

TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements with 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.

TEC’s effective tax rates for the six months ended June 30, 2018 and 2017 were 18.68% and 38.53%, respectively. The decrease in the effective tax rates in 2018 versus the same period in 2017 was primarily due to tax reform impacts. TEC’s effective tax rate for the six months ended June 30, 2018 differed from the statutory rate principally due to the amortization of the regulatory tax liability resulting from tax reform. See Note 3 for further information regarding the regulatory tax liability. TEC’s effective tax rate for the six months ended June 30, 2017 differed from the statutory rate principally due to state income taxes.

As of June 30, 2018, the amount of unrecognized tax benefits was $8 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 $8 million of unrecognized tax benefits at June 30, 2018, that, if recognized, would reduce TEC’s effective tax rate.

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 and Restoration Plan.

TECO Energy Benefit Cost
(millions)	Pension Benefits								Other Postretirement Benefits
Three months ended June 30,	2018				2017				2018			2017
Components of net periodic benefit cost
Service cost	$	6			$	5			$	0		$	0
Interest cost		7				9				2			2
Expected return on assets		(12	)			(12	)			0			0
Amortization of:
Prior service (benefit) cost		0				0				1			1
Actuarial (gain) loss		4				4				(1	)		(1	)
Settlement cost		2		⁽²⁾		0				0			0
Net periodic benefit cost	$	7			$	6			$	2		$	2
Six months ended June 30,
Components of net periodic benefit cost
Service cost	$	11			$	10			$	1		$	1
Interest cost		14				16				4			4
Expected return on assets		(24	)			(24	)			0			0
Amortization of:
Prior service (benefit) cost		0				0				0			0
Actuarial (gain) loss		9				8				(1	)		(1	)
Settlement cost		2		⁽²⁾		7		⁽¹⁾		0			0
Net periodic benefit cost	$	12			$	17			$	4		$	4

TEC’s portion of the net periodic benefit cost for the three months ended June 30, 2018 and 2017, respectively, was $6 million and $4 million for pension benefits, and $2 million and $2 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the six months ended June 30, 2018 and 2017, respectively, was $9 million and $7 million for pension benefits, and $4 million and $3 million for other postretirement benefits

TECO Energy assumed a long-term EROA of 6.85% and a discount rate of 3.63% for pension benefits under its qualified pension plan for 2018. For TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 3.70% for 2018.

TECO Energy made contributions of $10 million and $25 million to its qualified pension plan in the six months ended June 30, 2018 and 2017, respectively. TEC’s portion of these contributions was $8 million and $20 million, respectively. TECO Energy and TEC do not expect to make additional contributions to the pension plan for the remainder of 2018.

Included in the benefit cost discussed above, for the three and six months ended June 30, 2018, TEC reclassified $4 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 $5 million for the three and six months ended June 30, 2017, respectively.

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


	June 30, 2018						December 31, 2017
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325	$	0	$	1	$	325	$	5	$	1
3-year accounts receivable facility ⁽³⁾		150		75		0		150		0		0
1-year term facility ⁽⁴⁾		300		300		0		300		300		0
Total	$	775	$	375	$	1	$	775	$	305	$	1

At June 30, 2018, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at June 30, 2018 and December 31, 2017 was 2.7% and 2.1%, respectively.

On March 23, 2018, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a Second Amended Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). TEC will pay program and liquidity fees, which total 70 basis points at June 30, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin. In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of June 30, 2018, TEC was in compliance with the requirements of the Loan Agreement.

At June 30, 2018, TEC’s long-term debt had a carrying amount of $2,205 million and an estimated fair market value of $2,073 million. At December 31, 2017, TEC’s total long-term debt had a carrying amount of $2,164 million and an estimated fair market value of $2,412 million. The fair value of debt securities determined using Level 1 measurements was zero at June 30, 2018 and $55 million at December 31, 2017. The fair value of the remaining debt securities is determined using Level 2 measurements (see Note 12 for information regarding the fair value hierarchy).

On June 7, 2018, TEC completed an offering of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048 (the TEC 2018 Notes). Until December 15, 2047, TEC may redeem all or any part of the TEC 2018 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2018 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2018 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2047, TEC may, at its option, redeem the TEC 2018 Notes, in whole or in part, at 100% of the principal amount of the TEC 2018 Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

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 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, 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 June 30, 2018, TEC has estimated its ultimate financial liability to be $28 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.

TEC has commitments for purchased power, long-term leases (primarily for land, building space, vehicles, office equipment and 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 June 30, 2018:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2018	$	17	$	2	$	308	$	248	$	575
2019		0		2		173		230		405
2020		0		2		52		178		232
2021		0		2		26		144		172
2022		0		2		8		136		146
Thereafter		0		36		0		1,122		1,158
Total future minimum payments	$	17	$	46	$	567	$	2,058	$	2,688

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 June 30, 2018, TEC was in compliance with all required financial covenants.

(millions)	Tampa								Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations				Company
2018
Revenues - external	$	509	$	110	$	0			$	619
Intracompany sales		1		5		(6	)			0
Total revenues		510		115		(6	)			619
Total interest charges		25		4		0				29
Net income	$	74	$	11	$	0			$	85
2017
Revenues - external	$	542	$	102	$	0			$	644
Intracompany sales		0		2		(2	)			0
Total revenues		542		104		(2	)			644
Total interest charges		26		4		0				30
Net income	$	76	$	10	$	0			$	86
Six months ended June 30,
2018
Revenues - external	$	970	$	246	$	0			$	1,216
Intracompany sales		1		11		(12	)			0
Total revenues		971		257		(12	)			1,216
Total interest charges		51		8		0				59
Net income	$	121	$	27	$	0			$	148
2017
Revenues - external	$	984	$	213	$	0			$	1,197
Intracompany sales		1		3		(4	)			0
Total revenues		985		216		(4	)			1,197
Total interest charges		52		7		0				59
Net income	$	119	$	23	$	0			$	142
Total assets at June 30, 2018	$	7,853	$	1,319	$	(508	)	⁽¹⁾	$	8,664
Total assets at December 31, 2017	$	7,635	$	1,284	$	(555	)	⁽¹⁾	$	8,364

The following disaggregates TEC’s revenue by major source for the three and six months ended June 30, 2018:

(millions)	Tampa							Tampa Electric
Three months ended June 30, 2018	Electric		PGS		Eliminations			Company
Electric revenue
Residential	$	241	$	0	$	0		$	241
Commercial		140		0		0			140
Industrial		40		0		0			40
Regulatory deferrals and unbilled revenue		24		0		0			24
Other ⁽¹⁾		65		0		(1	)		64
Total electric revenue		510		0		(1	)		509
Gas revenue
Residential		0		35		0			35
Commercial		0		37		0			37
Industrial ⁽²⁾		0		6		0			6
Other ⁽³⁾		0		37		(5	)		32
Total gas revenue		0		115		(5	)		110
Total revenue	$	510	$	115	$	(6	)	$	619
Six months ended June 30, 2018
Electric revenue
Residential	$	471	$	0	$	0		$	471
Commercial		272		0		0			272
Industrial		78		0		0			78
Regulatory deferrals and unbilled revenue		23		0		0			23
Other ⁽¹⁾		127		0		(1	)		126
Total electric revenue		971		0		(1	)		970
Gas revenue
Residential		0		91		0			91
Commercial		0		81		0			81
Industrial ⁽²⁾		0		11		0			11
Other ⁽³⁾		0		74		(11	)		63
Total gas revenue		0		257		(11	)		246
Total revenue	$	971	$	257	$	(12	)	$	1,216

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of June 30, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $140 million. As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2033.

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

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 and to optimize the utilization of its physical natural gas storage capacity.

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 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). 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, which includes a derivative volume of 2 MMBTUs.

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. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage capacity 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 these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income (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 June 30, 2018, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected.

The derivatives at June 30, 2018 and December 31, 2017 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current 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 June 30, 2018 and $1 million of derivative liabilities as of December 31, 2017. 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 June 30, 2018 and December 31, 2017.

The corresponding effect of these derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current regulatory assets and liabilities. Based on the fair value of the instruments at June 30, 2018, 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.

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 and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of June 30, 2018, 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.

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 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. TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis are derivative assets and liabilities, which are classified as Level 2. Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 11).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. As of June 30, 2018, 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 June 30, 2018 and December 31, 2017, 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.

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, 2017.

		Three months ended June 30,						Six months ended June 30,
(millions)		2018			2017			2018			2017
Revenues
	Tampa Electric	$	510		$	542		$	971		$	985
	PGS		115			104			257			216
	Eliminations		(6	)		(2	)		(12	)		(4	)
	TEC	$	619		$	644		$	1,216		$	1,197

Net income
	Tampa Electric	$	74		$	76		$	121		$	119
	PGS		11			10			27			23
	TEC	$	85		$	86		$	148		$	142

Second quarter 2018 net income was $85 million, compared with $86 million in the second quarter of 2017. Second quarter 2018 results were impacted by lower base revenues at Tampa Electric due to weather, higher depreciation expense and lower O&M expense (excluding FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement) at Tampa Electric, partially offset by higher base revenues at PGS due to customer growth. Base revenues are energy sales excluding clauses, gross receipts taxes and franchise fees. Clauses, gross receipts taxes and franchise fees do not have a material effect on net income as these revenues substantially represent a dollar-for-dollar recovery of clauses and other pass-through costs. See below for further detail on Tampa Electric’s and PGS’s operating results.

Year-to-date net income through the second quarter of 2018 was $148 million, compared with $142 million in the 2017 year-to-date period. Year-to-date 2018 results were impacted by increased base revenues at Tampa Electric and PGS due to favorable weather, customer growth, and higher base rates as a result of the expansion of the Polk Power Station on January 16, 2017 and lower O&M expense (excluding FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement) at Tampa Electric. This was partially offset by higher depreciation expense at both utilities and higher O&M expense at PGS. See below for further detail.

Amounts included in the operating company discussions below are pre-tax, except net income and income taxes.

Tampa Electric’s net income for the second quarter of 2018 was $74 million, compared with $76 million for the same period in 2017. Results reflected lower base revenues and higher depreciation expense, partially offset by lower O&M expense (excluding FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement).

Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in the second quarter of 2018 were 4% above normal and 7% below the 2017 period. Total net energy for load decreased 2.1% in the second quarter of 2018 compared with the same period in 2017. Base revenues were $4 million lower than in 2017, primarily driven by weather, partially offset by customer growth.

Operations and maintenance expense (excluding all FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement, which effectively offsets tax reform benefits of $30 million) was $3 million lower than in the 2017 quarter, primarily reflecting the timing of generation outages and cost management activities, partially offset by higher employee-related costs. See Note 3 to the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and storm settlement agreement. Depreciation and amortization expense increased $2 million in the second quarter of 2018 from normal additions to facilities to reliably serve customers.

Tampa Electric’s net income year-to-date 2018 was $121 million, compared with $119 million for the same period in 2017. Results reflected higher base revenues and lower O&M expense (excluding FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement), partially offset by higher depreciation expense.

Total degree days in Tampa Electric's service area in the year-to-date period of 2018 were 9% above normal and 3% above the 2017 period. Total net energy for load increased 1.1% in the year-to-date period of 2018 compared with the same period in 2017. Base revenues were $11 million higher than in 2017, primarily driven by weather, customer growth and higher base rates as a result of the expansion of the Polk Power Station, which went in service on January 16, 2017.

In the 2018 year-to-date period, operations and maintenance expense (excluding all FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement, which effectively offsets tax reform benefits of $48 million) was $3 million lower than the amount in 2017, primarily reflecting cost management activities partially offset by higher employee-related costs. See Note 3 to the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and storm settlement agreement. Depreciation and amortization expense increased $7 million in 2018 from normal additions to facilities to reliably serve customers.

Tampa Electric’s regulated operating statistics for the three and six months ended June 30, 2018 and 2017 are as follows:

(millions, except customers and total degree days)	Operating Revenues							Kilowatt-hour sales
Three months ended June 30,	2018		2017		% Change			2018		2017		% Change
By Customer Type
Residential	$	241	$	255		(5	)		2,133		2,294		(7	)
Commercial		140		149		(6	)		1,503		1,636		(8	)
Industrial		40		39		3			505		505		0
Other sales of electricity		46		41		12			473		416		14
Regulatory deferrals and unbilled revenue ⁽¹⁾		24		37		(35	)
Total energy sales		491		521		(6	)		4,614		4,851		(5	)
Off system sales		4		5		(20	)		113		148		(24	)
Other operating revenue		15		16		(6	)
Total revenues	$	510	$	542		(6	)		4,727		4,999		(5	)
Customers at June 30, (thousands)		757		746		1
Retail net energy for load (kilowatt hours)									5,262		5,376		(2	)
Total degree days									1,279		1,377		(7	)

Six months ended June 30,
By Customer Type
Residential	$	471	$	453		4			4,154		4,055		2
Commercial		272		280		(3	)		2,907		3,067		(5	)
Industrial		78		79		(1	)		978		1,008		(3	)
Other sales of electricity		90		77		17			921		802		15
Regulatory deferrals and unbilled revenue ⁽¹⁾		23		60		(62	)
Total energy sales		934		949		(2	)		8,960		8,932		0
Off system sales		8		6		33			205		184		11
Other operating revenue		29		30		(3	)
Total revenues	$	971	$	985		(1	)		9,165		9,116		1
Customers at June 30, (thousands)		757		746		1
Retail net energy for load (kilowatt hours)									9,742		9,637		1
Total degree days									1,979		1,930		3

PGS reported net income of $11 million for the second quarter, compared with $10 million in the 2017 quarter. Results reflect a 2.9% higher number of customers in the second quarter of 2018 compared to the second quarter of 2017. Base revenues were $2 million higher than in 2017, primarily driven by customer growth. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of deferring tax reform benefits, was $2 million higher than in the 2017 quarter primarily due to higher employee-related costs and contractor costs. Depreciation and amortization decreased $1 million in the second quarter of 2018 due to timing of amortization of the regulatory asset associated with MGP environmental remediation costs. Income taxes decreased $2 million compared to the 2017 second quarter primarily due to tax reform impacts, which were offset by the deferral of tax reform benefits included in operations and maintenance expense.

PGS reported net income of $27 million for the 2018 year-to-date period, compared with $23 million in the 2017 period. Base revenues were $8 million higher than in 2017, which reflects customer growth and higher therm sales primarily due to cooler first quarter weather compared to 2017. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of deferring tax reform benefits, was $4 million higher than in the 2017 period due to the same drivers as mentioned above. Depreciation and amortization was $2 million higher due to the timing of amortization of the regulatory asset associated with MGP environmental remediation costs and normal asset growth. Return on investment in cast iron and bare steel replacement rider was $1 million higher than in the 2017 year-to-date period. Income taxes were $6 million lower primarily due to tax reform impacts, which was partially offset by $5 million deferral of tax reform benefits included in operations and maintenance expense.

PGS’s regulated operating statistics for the three and six months ended June 30, 2018 and 2017 are as follows:

(millions, except customers)	Operating Revenues							Therms
Three months ended June 30,	2018		2017		% Change			2018		2017		% Change
By Customer Type
Residential	$	35	$	31		13			18		16		13
Commercial		37		35		6			125		120		4
Industrial		4		3		33			88		81		9
Off system sales		16		17		(6	)		50		46		9
Power generation		2		2		0			179		194		(8	)
Other revenues		17		14		21
Total	$	111	$	102		9			460		457		1
By Sales Type
System supply	$	61	$	56		9			74		69		7
Transportation		33		32		3			386		388		(1	)
Other revenues		17		14		21
Total	$	111	$	102		9			460		457		1
Customers at June 30, (thousands)		386		375		3

Six months ended June 30,
By Customer Type
Residential	$	91	$	73		25			53		44		20
Commercial		81		74		9			269		254		6
Industrial		8		7		14			178		168		6
Off system sales		31		27		15			86		74		16
Power generation		3		3		0			370		374		(1	)
Other revenues		36		27		33
Total	$	250	$	211		18			956		914		5
By Sales Type
System supply	$	144	$	118		22			152		130		17
Transportation		70		66		6			804		784		3
Other revenues		36		27		33
Total	$	250	$	211		18			956		914		5
Customers at June 30, (thousands)		386		375		3

The provisions for income taxes for the 2018 and 2017 year-to-date periods were $34 million and $89 million, respectively. The provision for income taxes for the 2018 year-to-date period decreased mainly due to tax reform impacts. See Note 4 to the TEC Consolidated Condensed Financial Statements for further information.

The table below sets forth the June 30, 2018 liquidity, cash balances and amounts available under the TEC credit facilities.

Cash flows from operating activities for the six months ended June 30, 2018 were $346 million, an increase of $118 million compared to the same period in 2017. The increase is primarily due to lower payments in 2018 for products and services, lower clause under-recoveries in 2018 and lower fuel inventory due to decreased use of coal units.

Cash flows from financing activities for the six months ended June 30, 2018 resulted in net cash inflows of $166 million. TEC received $215 million of equity contributions from TECO Energy, proceeds from a long-term debt issuance of $345 million (see Note 7 to the TEC Consolidated Condensed Financial Statements for details) and $70 million of net proceeds from borrowings under credit agreements, partially offset by the repayment of long-term debt of $304 million and dividend payments to TECO Energy of $160 million.

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 June 30, 2018, 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 June 30, 2018. Reference is made to the specific agreements and instruments for more details.

Certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 11 to the TEC Consolidated Condensed Financial Statements).

See Note 8 to the TEC Consolidated Condensed Financial Statements for information regarding TEC’s commitments and contingencies as of June 30, 2018.

In 2018, TEC expects to invest approximately $1,360 million in capital projects, excluding AFUDC-debt and equity. This represents an increase of approximately $160 million from the 2018 forecasted capital investments amount disclosed in TEC’s Annual Report on Form 10-K for the year ended December 31, 2017. The increase is primarily due to timing of solar generation and the modernization of the Big Bend Power Station.

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 and approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel, which will improve land, water and air emissions at Tampa Electric. This project is estimated to provide savings to customers compared to operating the unit on coal to the end of its life. The project will be capable of producing 1,090 MW when completed in 2023. Big Bend Unit 2 will be retired early. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric is not required to file an asset recovery filing for early retired assets. Tampa Electric expects to recover the remaining net book value of retired assets. These investments will change Tampa Electric’s fuel mix from 69% natural gas, 24% coal and 7% other sources in 2017 of which less than 0.5% was solar, to approximately 75% natural gas, 12% coal, 7% solar and 6% other sources in 2023.

TEC intends to fund those capital expenditures with available cash on hand, cash generated from operating activities, and cash from equity contributions and debt issuances so that Tampa Electric and PGS maintain their capital structures consistent with existing regulatory arrangements. Actual capital expenditures could vary materially due to changes in schedule, costs for materials or labor or changes in plans.

All natural gas derivatives were entered into by TEC to manage the impact of natural gas prices on customers and to optimize the utilization of its physical natural gas storage capacity.

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 derivative 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 12 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 June 30, 2018, the fair value of derivatives was not materially affected by nonperformance risk.

Critical accounting policies and estimates have not materially changed in 2018. For further discussion of critical accounting policies and estimates, see TEC’s Annual Report on Form 10-K for the year ended December 31, 2017.

Information required by Item 3 is omitted pursuant to General Instruction H(2) of Form 10-Q.

From time to time, TEC is involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of 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. For a discussion of legal proceedings and environmental matters, see Note 8 of the TEC Consolidated Condensed Financial Statements.

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.

Term		Meaning
NAV		net asset value
Note		Note to consolidated financial statements
NO_x		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
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
SoBRAs		solar base rate adjustments
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


(millions)
Credit facilities	$	775
Drawn amounts/letters of credit		376
Available credit facilities		399
Cash and short-term investments		15
Total liquidity	$	414

			Calculation at
Instrument	Financial Covenant ⁽¹⁾	Requirement/Restriction	June 30, 2018
Credit facility - $325 million ⁽²⁾	Debt/capital	Cannot exceed 65%	44.8%
Credit facility - $300 million ⁽²⁾	Debt/capital	Cannot exceed 65%	44.8%
Accounts receivable credit facility - $150 million ⁽²⁾	Debt/capital	Cannot exceed 65%	44.8%

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

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).	*

4.1	Thirteenth Supplemental Indenture dated as of June 7, 2018, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.9, Form 8-K dated June 7, 2018 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

	TAMPA ELECTRIC COMPANY
	(Registrant)

Date: August 9, 2018	By:	/s/ Gregory W. Blunden
		Gregory W. Blunden
		Senior Vice President-Finance and Accounting, Treasurer and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)