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

Indicate by check mark whether the registrant has submitted electronically and posted on ~~their~~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 ~~registrants were~~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 9, 2017,~~May 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:

Assets	June 30,			December 31,			March 31,			December 31,
(millions)	2017			2016			2018			2017
Property, plant and equipment
Utility plant
Electric	$	8,374		$	7,624		$	8,606		$	8,555
Gas		1,547			1,503			1,641			1,609
Construction work in progress		250			892			301			263
Utility plant, at original costs		10,171			10,019			10,548			10,427
Accumulated depreciation		(2,891	)		(2,826	)		(3,046	)		(2,994	)
Utility plant, net		7,280			7,193			7,502			7,433
Other property		11			10			11			11
Total property, plant and equipment, net		7,291			7,203			7,513			7,444

Current assets
Cash and cash equivalents		15			10			16			13
Receivables, less allowance for uncollectibles of $1 at both June 30, 2017 and December 31, 2016		236			206
Receivables, less allowance for uncollectibles of $1 at both March 31, 2018 and December 31, 2017								225			257
Due from affiliates		3			7			4			5
Inventories, at average cost
Fuel		84			77			55			60
Materials and supplies		95			86			93			90
Derivative assets		1			15
Regulatory assets		26			28			67			77
Prepayments and other current assets		26			21			19			13
Total current assets		486			450			479			515

Deferred debits
Regulatory assets		400			393			351			356
Other		37			37			52			49
Total deferred debits		437			430			403			405
Total assets	$	8,214		$	8,083		$	8,395		$	8,364

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

Liabilities and Capitalization	June 30,			December 31,			March 31,			December 31,
(millions)	2017			2016			2018			2017
Capitalization
Common stock	$	2,513		$	2,456		$	2,755		$	2,645
Accumulated other comprehensive loss		(2	)		(3	)		(2	)		(2	)
Retained earnings		344			311			301			335
Total capital		2,855			2,764			3,054			2,978
Long-term debt		1,859			2,163			1,860			1,860
Total capitalization		4,714			4,927			4,914			4,838

Current liabilities
Long term debt due within one year		304			0
Long-term debt due within one year								304			304
Notes payable		298			170			300			305
Accounts payable		158			262			174			233
Due to affiliates		11			25			17			21
Customer deposits		135			146			130			131
Regulatory liabilities		87			154			67			58
Accrued interest		18			16			37			14
Accrued taxes		49			12			29			12
Other		10			11			24			44
Total current liabilities		1,070			796			1,082			1,122

Deferred credits
Long-term liabilities
Deferred income taxes		1,476			1,407			841			825
Investment tax credits		22			11
Regulatory liabilities		575			591			1,218			1,227
Deferred credits and other liabilities		357			351			340			352
Total deferred credits		2,430			2,360
Total long-term liabilities								2,399			2,404

Commitments and Contingencies (see Note 8)
Commitments and Contingencies (see Note 8)

Total liabilities and capitalization	$	8,214		$	8,083		$	8,395		$	8,364

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

Three months ended June 30,

(millions)
2017

2016

Revenues

Electric
$
542

$
499

Gas

102

100

Total revenues

644

599

Expenses

Fuel

165

138

Purchased power

8

28

Cost of natural gas sold

35

36

Operations and maintenance

131

133

Depreciation and amortization

88

81

Taxes, other than income

49

47

Total expenses

476

463

Income from operations

168

136

Other income

Allowance for equity funds used during construction

0

6

Other income, net

2

1

Total other income

2

7

Interest charges

Interest on long-term debt

28

28

Other interest

2

1

Allowance for borrowed funds used during construction

0

(3
)
Total interest charges

30

26

Income before provision for income taxes

140

117

Provision for income taxes

54

41

Net income
$
86

$
76

Comprehensive income
$
86

$
76

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

	Six months ended June 30,						Three months ended March 31,
(millions)	2017			2016			2018		2017
Revenues
Electric	$	984		$	923		$	461	$	442
Gas		213			227			136		111
Total revenues		1,197			1,150			597		553
Expenses
Fuel		296			253			122		131
Purchased power		15			42			13		7
Cost of natural gas sold		71			86			55		36
Operations and maintenance		259			254			157		128
Depreciation and amortization		173			162			93		85
Taxes, other than income		98			96			52		49
Total expenses		912			893			492		436
Income from operations		285			257			105		117
Other income
Allowance for equity funds used during construction		1			12			0		1
Other income, net		4			2			2		2
Total other income		5			14			2		3
Interest charges
Interest on long-term debt		56			57			27		28
Interest expense		4			2
Other interest								3		2
Allowance for borrowed funds used during construction		(1	)		(5	)		0		(1	)
Total interest charges		59			54			30		29
Income before provision for income taxes		231			217			77		91
Provision for income taxes		89			78			14		35
Net income	$	142		$	139		$	63	$	56
Other comprehensive income, net of tax
Gain on cash flow hedges		1			0
Total other comprehensive income, net of tax		1			0
Comprehensive income	$	143		$	139		$	63	$	56

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

	Six months ended June 30,						Three months ended March 31,
(millions)	2017			2016			2018			2017
Cash flows from operating activities
Net income	$	142		$	139		$	63		$	56
Adjustments to reconcile net income to net cash from operating activities:
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		173			162			93			85
Deferred income taxes and investment tax credits		87			37			8			35
Allowance for equity funds used during construction		(1	)		(12	)
Deferred recovery clauses		(52	)		41			(7	)		(23	)
Receivables, less allowance for uncollectibles		(23	)		(8	)		32			11
Inventories		(16	)		1			2			(8	)
Taxes accrued		27			120			23			16
Interest accrued								23			22
Accounts payable		(88	)		4			(68	)		(101	)
Regulatory assets and liabilities								20			(5	)
Other		(21	)		(21	)		(32	)		(12	)
Cash flows from operating activities		228			463			157			76
Cash flows from investing activities
Cash flows used in investing activities
Capital expenditures		(299	)		(354	)		(162	)		(143	)
Net proceeds from sale of assets		0			9
Cash flows used in investing activities		(299	)		(345	)		(162	)		(143	)
Cash flows from financing activities
Common stock		58			90
Repayment of long-term debt		0			(83	)
Net increase in short-term debt		128			62
Dividends		(109	)		(182	)
Equity contributions from TECO Energy								110			27
Net increase (decrease) in short-term debt								(5	)		106
Dividends to TECO Energy								(97	)		(65	)
Other financing activities		(1	)		0			0			(1	)
Cash flows from (used in) financing activities		76			(113	)
Cash flows from financing activities								8			67
Net increase in cash and cash equivalents		5			5			3			0
Cash and cash equivalents at beginning of period		10			9			13			10
Cash and cash equivalents at end of period	$	15		$	14		$	16		$	10
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(24	)	$	(14	)	$	0		$	(12	)

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, ~~2016~~2017 for a complete discussion of accounting policies. The significant accounting policies for TEC include:

~~For the purposes~~TEC is a wholly owned subsidiary of ~~its consolidated financial reporting,~~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, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, and the results of operations and cash flows for the periods ended ~~June 30, 2017~~March 31, 2018 and ~~2016.~~2017. The results of operations for the three ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, ~~2017.~~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 ~~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.

Electric revenues are recognized when obligations under the terms of a contract are satisfied, which is ~~a wholly owned subsidiary~~primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of ~~TECO Energy. On July 1, 2016, TECO Energy~~the electricity. Electric revenues are recognized on an accrual basis and ~~Emera completed~~include billed and unbilled revenues. Revenues related to the ~~Merger contemplated~~sale of electricity are recognized at rates approved by the ~~Merger Agreement entered into~~respective regulator and recorded based on ~~September 4, 2015. Therefore,~~metered usage, which occur on a periodic, systematic basis. 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 are recognized when obligations under the terms of a contract are satisfied, which is 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. 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 ~~continues~~collects concurrent with revenue-producing activities are excluded from revenue.

Receivables from contracts with customers, which consist of services billed to residential, commercial, industrial and other customers, were $218 million and $229 million as of March 31, 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 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.

As of ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, unbilled revenues of ~~$66~~$62 million and ~~$54~~$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 $29 million and ~~$54~~$26 million for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017, ~~respectively, and $29 million and $57 million for the three and six months ended June 30, 2016,~~ respectively.

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

On January 1, 2018, TEC adopted Accounting Standards Update (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 consolidated condensed income statement for the three months ended March 31, 2018. The impact of the adoption of the new standard is expected to be immaterial to TEC’s net income 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 ~~Accounting Standard Updates (ASU)~~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, ~~2016,~~2017, with the exception of the items noted below.

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers~~, which creates a new, principle-based revenue recognition framework, which has been codified as ASC Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those

~~periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. TEC will adopt this guidance effective January 1, 2018.~~

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. TEC will adopt the standard using the modified retrospective approach. TEC continues to evaluate the impact of this standard, including financial statement disclosure requirements. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments.

In February 2016, the FASB issued ASU 2016-02, ~~Leases.~~Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as ~~lease~~ assets and ~~lease~~ liabilities on the balance sheet. The effect of leases on the ~~Consolidated Statements~~consolidated statements of ~~Income~~income and the ~~Consolidated Statements~~consolidated statements of ~~Cash Flows~~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 elect this practical expedient. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is ~~currently~~expected to be finalized in the second quarter of 2018. TEC expects to elect this practical expedient.

TEC expects that the standard will affect its 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 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. Remaining activities to be performed include evaluating the ~~impact~~available implementation alternatives, 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.

Reclassification of ~~adoption of this standard on its consolidated financial statements.~~

~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~Certain Tax Effects from Accumulated Other Comprehensive Income

In ~~March 2017,~~February 2018, the FASB issued ASU ~~2017-07,~~No. 2018-02, ~~Compensation—Retirement Benefits~~Income Statement - Reporting Comprehensive Income (Topic ~~715)~~220): ~~Improving~~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 ~~Presentation of Net Periodic Pension Cost~~Tax Cuts and ~~Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or~~Jobs Act that would otherwise be stranded in accumulated 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 under this guidance.comprehensive income. This guidance ~~will be~~is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, ~~2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization.~~2018, with early adoption permitted. TEC is currently in the process of evaluating the impact of ~~the~~ adoption of this standard on ~~the~~its consolidated financial ~~statements, including the eligibility for capitalization of the other components of net benefit cost given the application of ASC 980~~ ~~Regulated Operations. TEC will adopt this guidance effective January 1, 2018.~~statements.

~~Tampa Electric’s results reflect a stipulation~~ filed with the FPSC an amended and restated settlement agreement ~~entered into on September 6, 2013, between Tampa Electric and~~that replaced the ~~intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s~~ 2013 base rate ~~proceeding. On~~settlement agreement and extended it four years through 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 ~~11, 2013, the FPSC unanimously voted~~2018 through January 2021. In order for each tranche of SoBRAs to ~~approve the stipulation~~take effect, Tampa Electric must show that each tranche is cost-effective and ~~settlement agreement.~~

~~This agreement provided~~each individual project has a cost cap of $1,500/kWac. Additionally, in order to receive a SoBRA for the ~~following revenue increases: $58~~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 ~~November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015,~~date and ~~an additional $110 million effective~~ the date ~~that~~ the ~~expansion~~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 ~~Tampa Electric’s Polk Power Station went into service, which was January 16, 2017.~~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 in estimated revenue requirements. The agreement also provides for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that FPSC approved the tariffs on the first SoBRA filing on May 8, 2018.

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.

As a result of ~~several~~Tampa Electric’s 2013 rate case settlement, in the event of a named ~~storms, including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew,~~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 $9costs for restoration currently estimated to be approximately $103 million, of which $92 million was charged to the storm reserve, $4 million was charged to O&M expense and $7 million was charged to capital expenditures. At March 31, 2018, the amount of estimated costs charged to the storm reserve regulatory liability exceeded the balance in ~~2016. In 2017,~~the storm reserve by $46 million, which is recorded as a regulatory asset on the balance sheet as allowed by an FPSC order. Tampa Electric petitioned the FPSC ~~to seek full~~on December 28, 2017 for recovery of ~~those costs, subsequently withdrew the petition, applied the~~estimated storm costs in excess of the reserve and to replenish the balance in the reserve to the ~~transmission and delivery storm reserve, and concluded to seek recovery~~$56 million level that existed as of ~~storm costs once~~October 31, 2013. An amended petition was filed with the ~~reserve is fully depleted.~~FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below.

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and decrease the bottom of the ROE range from 9.75% to 9.25%. The new bottom of the ROE range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020. The top of the ROE range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. On February 7, 2017,March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addresses both the ~~settlement agreement. No change in~~recovery of storm costs and the return of tax reform benefits to customers (see Note 4) while keeping customer rates ~~resulted from this agreement.~~

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 ~~part~~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 ~~settlement, PGS and OPC agreed that at least $32 million~~recovery of ~~PGS’s~~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. The 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~~remainder of 2018 as a credit against the recognition of storm expense beginning on April 1, 2018. 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 ~~amortized over a two-year recovery period~~determined in separate regulatory proceedings. Any difference will be trued up and recovered from or returned to customers in 2019. In addition, beginning in ~~2016. In 2016,~~ January 2019, Tampa Electric will reflect the full impact of tax reform on its base rates. Hearings on the tax reform impacts for all state utilities are tentatively scheduled for the second half of 2018.

PGS ~~recorded $16 million of this amortization expense. This additional amortization expense~~Base Rates

PGS’s base rates were established in ~~2016~~May 2009. An updated settlement agreement was ~~offset~~approved by the ~~decrease~~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 ~~depreciation expense as discussed above with no impact~~Florida without an existing tax reform settlement provision, including PGS. As a result, PGS deferred the estimated tax reform benefits to ~~2016 earnings. For the three~~customers and ~~six months ended June 30, 2017, PGS~~ recorded ~~amortization expense~~a regulatory tax liability of $2 million for the period February 6 to March 31, 2018. PGS will file testimony supporting the calculation of the tax benefits and ~~$3 million, respectively.~~ flowback of its excess deferred taxes on May 31, 2018.

Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. ~~Areas of applicability include: revenue recognition resulting~~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 ~~cost-recovery clauses~~previous collections for costs that ~~provide for monthly billing charges~~are not likely to ~~reflect increases~~be incurred or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved ~~costs such as future storm damage or the future removal of property.~~costs.

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

Regulatory Assets and Liabilities
(millions)	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	84	$	86	$	44	$	45
Cost-recovery clauses - deferred balances ⁽²⁾		8		8		6		13
Environmental remediation⁽³⁾		34		37		29		33
Postretirement benefits ⁽⁴⁾		279		272		268		272
Storm reserve ⁽⁵⁾						46		47
Other		21		18		25		23
Total regulatory assets		426		421		418		433
Less: Current portion		26		28		67		77
Long-term regulatory assets	$	400	$	393	$	351	$	356
Regulatory liabilities:
Regulatory tax liability	$	12	$	6
Cost-recovery clauses - deferred balances ⁽²⁾		59		112
Cost-recovery clauses - offsets to derivative assets⁽²⁾		1		17
Transmission and delivery storm reserve		47		56
Regulatory tax liability⁽⁶⁾					$	725	$	730
Tax reform and storm agreement⁽⁷⁾						19		0
Cost-recovery clauses ⁽²⁾						20		32
Accumulated reserve - cost of removal⁽⁵⁾⁽⁸⁾		536		547		516		518
Other		7		7		5		5
Total regulatory liabilities		662		745		1,285		1,285
Less: Current portion		87		154		67		58
Long-term regulatory liabilities	$	575	$	591	$	1,218	$	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, ~~2016~~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 ~~due~~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 ~~Merger~~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 ~~Emera,~~ 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 quarter of 2018.

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 ofwith TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution.

The IRS concluded its examination of TECO Energy’s 2015 consolidated federal income tax return in March 2017 with no changes required. The U.S. federal statute of limitations remains open for the year 2013 and forward. The short tax year ending June 30, 2016 is currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only able to participate in the CAP through its short tax year ending June 30, 2016.

TEC’s effective tax rates for the ~~six~~three months ended ~~June 30,~~March 31, 2018 and 2017 were 18.18% and ~~2016 were 38.53% and 35.94%~~38.46%, respectively. The ~~increase~~decrease in the ~~six-month~~ effective tax ~~rate~~rates in ~~2017~~2018 versus the same period in ~~2016 is~~2017 was primarily due to ~~lower AFUDC-equity and production deduction~~ tax ~~benefits.~~reform impacts. TEC’s effective tax rate for the ~~six~~three months ended ~~June 30, 2017 differs~~March 31, 2018 differed from the statutory rate principally due to ~~state income taxes.~~tax reform impacts. TEC’s effective

tax rate for the ~~six~~three months ended ~~June 30, 2016 differs~~March 31, 2017 differed from the statutory rate principally due to ~~state income taxes offset by~~the tax ~~benefits~~benefit related to ~~AFUDC-equity and production deduction.~~AFUDC-equity.

As of ~~June 30, 2017,~~March 31, 2018, the amount of unrecognized tax benefits was $7$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 ~~expected~~ongoing audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. TEC had $7$8 million of unrecognized tax benefits at ~~June 30, 2017,~~March 31, 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.

TECO Energy Benefit Cost
(millions)	Pension Benefits							Other Postretirement Benefits						Pension Benefits							Other Postretirement Benefits
Three months ended June 30,	2017				2016			2017			2016
Three months ended March 31,														2018			2017				2018			2017
Components of net periodic benefit cost
Service cost	$	5			$	5		$	0		$	1		$	5		$	5			$	1		$	1
Interest cost		9				8			2			2			7			7				2			2
Expected return on assets		(12	)			(11	)		0			0			(12	)		(12	)			0			0
Amortization of:
Prior service (benefit) cost		0				0			1			(1	)		0			0				(1	)		(1	)
Actuarial loss		4				3			(1	)		0
Curtailment cost		0				1			0			0
Actuarial (gain) loss															5			4				0			0
Settlement cost		0		⁽¹⁾		1			0			0			0			7		⁽¹⁾		0			0
Net periodic benefit cost	$	6			$	7		$	2		$	2		$	5		$	11			$	2		$	2
Six months ended June 30,
Components of net periodic benefit cost
Service cost	$	10			$	9		$	1		$	1
Interest cost		16				16			4			4
Expected return on assets		(24	)			(22	)		0			(1	)
Amortization of:
Prior service (benefit) cost		0				0			0			(1	)
Actuarial loss		8				7			(1	)		0
Regulatory asset		0				0			0			1
Curtailment cost		0				1			0			0
Settlement cost		7		⁽¹⁾		1			0			0
Net periodic benefit cost	$	17			$	12		$	4		$	4

TEC’s portion of the net periodic benefit cost for the three months ended ~~June 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively, was $4$3 million and $3 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, 2017 and 2016, respectively, was $7 million and $6 million for pension benefits, and $3 million and $3$1 million for other postretirement benefits.

For the ~~2017~~2018 plan year, TECO Energy assumed a long-term EROA of ~~7.00%~~6.85% and a discount rate of ~~4.16%~~3.63% for pension benefits under its qualified pension plan. For the ~~January 1, 2017 measurement~~2018 plan year of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of ~~4.28%~~3.70%.

TECO Energy made contributions of ~~$25~~$10 million and ~~$16~~$14 million to its qualified pension plan in the ~~six~~three months ended ~~June 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively. TEC’s portion of these contributions was ~~$20~~$8 million and ~~$13~~$11 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,~~March 31, 2018 and 2017, TEC reclassified $3$4 million and $5$2 million, respectively, of unamortized prior service ~~benefit~~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, 2016, respectively.~~income.

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


	June 30, 2017						December 31, 2016						March 31, 2018						December 31, 2017
					Letters						Letters						Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit		Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325	$	174	$	1	$	325	$	40	$	1	$	325	$	0	$	1	$	325	$	5	$	1
3-year accounts receivable facility ⁽³⁾		150		124		0		150		130		0		150		0		0		150		0		0
1-year term facility ⁽⁴⁾														300		300		0		300		300		0
Total	$	475	$	298	$	1	$	475	$	170	$	1	$	775	$	300	$	1	$	775	$	305	$	1

At ~~June 30, 2017,~~March 31, 2018, these credit facilities required commitment fees ranging from 12.5 to ~~30.0~~35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 was ~~1.89%~~2.3% and ~~1.49%~~2.1%, respectively.

On March ~~22, 2017,~~23, 2018, TEC amended its ~~$325~~$150 million ~~bank credit~~accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a ~~Fifth~~Second Amended Loan and ~~Restated Credit Agreement.~~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 March 31, 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 ~~amendment (i) extended~~Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the ~~maturity date~~federal funds rate, or the London interbank deposit rate, plus a margin. In the case of default, as defined under the terms of the ~~credit facility from December 17,~~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 March 31, 2018, ~~to March 22, 2022 (subject to further extension~~TEC was in compliance with the ~~consent~~requirements of ~~each lender); (ii) included a $50 million letter of credit facility; and (iii) made other technical changes.~~

At ~~June 30,~~March 31, 2018, TEC’s long-term debt had a carrying amount of $2,164 million and an estimated fair market value of $2,341 million. At December 31, 2017, TEC’s total long-term debt had a carrying amount of ~~$2,163~~$2,164 million and an estimated fair market value of ~~$2,379~~$2,412 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 ~~$57 million and $58~~$55 million at ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016, respectively.~~2017. The fair value of the remaining debt securities is determined using Level 2 measurements (see Note 1112 for information regarding the fair value hierarchy).

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.~~

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, 2017,~~March 31, 2018, TEC has estimated its ultimate financial liability to be ~~$30~~$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. ~~See~~ ~~Note 3~~ ~~for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this reserve.~~

TEC has commitments for purchased power and long-term leases, primarily for land, building space, vehicles, office equipment, ~~and~~ heavy ~~equipment. TEC also has~~equipment, other purchase obligations, ~~for~~ long-term service agreements and capital projects. In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at ~~June 30, 2017:~~March 31, 2018:

					Long-term Service										Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable				Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total		Power		Leases		Projects		Commitments		Total
Year ended December 31:
2017	$	5	$	3	$	38	$	303	$	349
2018		10		4		11		257		282	$	15	$	2	$	412	$	359	$	788
2019		0		2		11		186		199		0		2		155		237		394
2020		0		2		6		163		171		0		2		21		186		209
2021		0		2		7		132		141		0		2		15		155		172
2022												0		2		8		150		160
Thereafter		0		38		25		1,157		1,220		0		36		23		1,124		1,183
Total future minimum payments	$	15	$	51	$	98	$	2,198	$	2,362	$	15	$	46	$	634	$	2,211	$	2,906

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking ~~agreements. TEC~~agreements and has certain restrictive covenants in specific agreements and debt instruments. At ~~June 30, 2017,~~March 31, 2018, TEC was in compliance with all required financial covenants.

(millions)	Tampa								Tampa Electric		Tampa								Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations				Company
Three months ended March 31,											Electric		PGS		Eliminations				Company
2018
Revenues - external											$	461	$	136	$	0			$	597
Intracompany sales												0		6		(6	)			0
Total revenues												461		142		(6	)			597
Total interest charges												26		4		0				30
Net income											$	48	$	15	$	0			$	63
2017
Revenues - external	$	542	$	102	$	0			$	644	$	442	$	111	$	0			$	553
Intracompany sales		0		2		(2	)			0		0		1		(1	)			0
Total revenues		542		104		(2	)			644		442		112		(1	)			553
Total interest charges		26		4		0				30		25		4		0				29
Net income	$	76	$	10	$	0			$	86	$	42	$	14	$	0			$	56
2016
Revenues - external	$	499	$	100	$	0			$	599
Intracompany sales		0		2		(2	)			0
Total revenues		499		102		(2	)			599
Total interest charges		22		4		0				26
Net income	$	69	$	7	$	0			$	76
Six months ended June 30,
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
2016
Revenues - external	$	923	$	227	$	0			$	1,150
Intracompany sales		1		6		(7	)			0
Total revenues		924		233		(7	)			1,150
Total interest charges		47		7		0				54
Net income	$	119	$	20	$	0			$	139
Total assets at June 30, 2017	$	7,486	$	1,228	$	(500	)	⁽¹⁾	$	8,214
Total assets at December 31, 2016	$	7,357	$	1,191	$	(465	)	⁽¹⁾	$	8,083
Total assets at March 31, 2018											$	7,596	$	1,297	$	(498	)	⁽¹⁾	$	8,395
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 months ended March 31, 2018:

(millions)	Tampa								Tampa Electric
Three months ended March 31, 2018	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	230		$	0	$	0		$	230
Commercial		132			0		0			132
Industrial		38			0		0			38
Regulatory deferrals and unbilled revenue		(1	)		0		0			(1	)
Other ⁽¹⁾		62			0		0			62
Total electric revenue		461			0		0			461
Gas revenue
Residential		0			56		0			56
Commercial		0			44		0			44
Industrial ⁽²⁾		0			5		0			5
Other ⁽³⁾		0			37		(6	)		31
Total gas revenue		0			142		(6	)		136
Total revenue	$	461		$	142	$	(6	)	$	597

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of March 31, 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.~~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 November 2016, Tampa Electric and the other major electric IOUs in Florida signed a stipulation agreement approved by the FPSC calling for a one-year moratorium on hedging of natural gas purchases. ~~The stipulation agreement called for~~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 ~~oversee one or more workshops~~the variability in ~~2017~~future cash flows extends to ~~seek~~November 30, 2018 for financial natural gas contracts, which includes a ~~cost-effective way to insure against rising gas prices. In April 2017, the FPSC decided to hold a hearing in the fall~~derivative volume of ~~2017 to consider whether hedging should resume or be discontinued altogether.~~5 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 and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see~~ ~~Note 11). The changes in fair value that are recorded in OCI are not immediately recognized in current net income.~~

As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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 ~~hedging~~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, 2017,~~March 31, 2018, 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 ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current ~~and long term~~ assets and liabilities on a net basis as permitted by their respective master netting agreements. ~~Derivative~~There were approximately zero derivative assets ~~totaled~~and liabilities as of March 31, 2018 and $1 million ~~and $17 million as~~ of ~~June 30, 2017 and December 31, 2016, respectively. There were no~~ derivative liabilities as of ~~June 30,~~December 31, 2017 and ~~December 31, 2016.~~2016, respectively. 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, 2017~~March 31, 2018 and December 31, ~~2016.~~2017.

All of the derivative asset and liabilities at June 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 ~~June 30, 2017,~~March 31, 2018, there are no net ~~pretax~~pre-tax reductions in fuel costs ~~of $1 million~~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 months ended June 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 six months ended June 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. The following table presents TEC’s derivative volumes that, as of June 30, 2017, are expected to settle during the 2017 and 2018 fiscal years:

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.~~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, 2017,~~March 31, 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 ~~such, fair value is~~ a ~~market-based measurement that is determined based upon~~basis for considering assumptions that market participants would use in pricing an asset or ~~liability. As a basis for considering such assumptions,~~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.

~~Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:~~

The fair value of financial instruments is determined by using various market data and other valuation techniques.

~~The following tables set forth by level within the fair value hierarchy,~~ TEC’s financial assets and liabilities that were accounted for at fair value on a recurring ~~basis. As required by accounting standards for fair value measurements, financial~~basis are derivative assets and liabilities, which are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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 1011).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. ~~At June 30, 2017,~~As of March 31, 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, 2017~~March 31, 2018 and December 31, ~~2016,~~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.

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 $4 million and $8 million under these PPAs for the three and six months ended June 30, 2017, respectively, and $16 million and $29 million for the three and six months ended June 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.

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.~~2017.

			Three months ended June 30,						Six months ended June 30,								Three months ended March 31,
(millions)			2017			2016			2017			2016					2018			2017
Segment revenues
Revenues															Revenues
		Tampa Electric	$	542		$	499		$	985		$	924			Tampa Electric	$	461		$	442
		PGS		104			102			216			233			PGS		142			112
		Eliminations		(2	)		(2	)		(4	)		(7	)		Eliminations		(6	)		(1	)
			$	644		$	599		$	1,197		$	1,150			TEC	$	597		$	553

Net income	Net income														Net income
		Tampa Electric	$	76		$	69		$	119		$	119			Tampa Electric	$	48		$	42
		PGS		10			7			23			20			PGS		15			14
			$	86		$	76		$	142		$	139			TEC	$	63		$	56

~~Second~~First quarter ~~2017~~2018 net income was ~~$86~~$63 million, compared with ~~$76~~$56 million in the ~~second~~first quarter of ~~2016. Second~~2017. First quarter ~~2017~~2018 results were impacted by increased revenue at Tampa Electric and PGS due to favorable weather, customer growth, and higher base rates ~~at Tampa Electric that went into effect with~~as a result of the ~~completion~~expansion of the Polk Power Station ~~expansion in~~on January 16, 2017, ~~Tampa Electric and PGS customer growth, and warmer spring weather,~~ partially offset by higher O&M and depreciation ~~expense and lower AFUDC at Tampa Electric. See below for further detail.~~

Year-to-date net income through the second quarter of 2017 was $142 million, compared with $139 million in the 2016 year-to-date 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 higher operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, at Tampa Electric and PGS, and higher depreciation expense and lower AFUDC at Tampa Electric.expenses. See below for further detail.

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

Tampa Electric’s net income for the ~~second~~first quarter of ~~2017~~2018 was ~~$76~~$48 million, compared with ~~$69~~$42 million for the same period in ~~2016.~~2017. Results ~~for the quarter~~ reflected higher base revenue from higher base rates as a result of the 2013 rate case settlement related to the completion of the Polk Power Station expansion in January 2017. Results reflected lower operations and maintenance expense excluding all FPSC-approved cost-recovery clauses,revenues partially offset by higher depreciation ~~and property tax expenses. Second-quarter net income in 2017 included less than $1 million of AFUDC-equity, the allowed equity cost capitalized to construction costs, which decreased~~

compared with $6 million in the same period in 2016 due to the completion of the Polk Power Station expansion in January 2017. Results reflect a 2.1% higher number of customers at June 30, 2017 compared to June 30, 2016.expense.

Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in the ~~second~~first quarter of ~~2017~~2018 were ~~13%~~19% above normal and ~~10%~~27% above the ~~2016 period as a result of warmer than normal spring weather.~~2017 period. Total net energy for load increased ~~2.2%~~5.1% in the ~~second~~first quarter of ~~2017,~~2018 compared with the same period in ~~2016. In the 2017 period, pretax~~2017. Pre-tax base revenues were ~~$34~~$14 million higher than in ~~2016,~~2017, primarily driven by ~~approximately $30 million pre-tax from~~weather and higher base rates as a result of the expansion of the Polk Power Station, which went in service on January 16, 2017. ~~The quarter base revenues also increased as~~Results reflect a ~~result~~1.3% increase in number of ~~customer growth and the warmer than normal spring weather.~~ customers at March 31, 2018 compared to March 31, 2017.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of the regulatory agreement netting the recovery of storm costs with tax reform benefits of $14 million ($19 million pre-tax), was $2$1 million ~~lower~~higher than in the ~~2016~~2017 quarter, primarily reflecting ~~lower costs~~the timing of generation outages. See Note 3 to ~~operate~~the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and ~~maintain the generation assets in 2017 compared to 2016.~~storm settlement agreement. Depreciation and amortization expense increased $5$3 million in the ~~second~~first quarter of ~~2017, as the Polk Power Station expansion was placed in service in January 2017 and~~2018 from normal additions to facilities to reliably serve customers.

Tampa Electric’s year-to-date net income through the second quarter of 2017 and 2016 were consistent at $119 million. Results reflected higher base revenues from higher base rates described above and higher operation and maintenance, depreciation and property tax expense. Year-to-date net income in 2017 included $1 million of AFUDC-equity, the allowed equity cost capitalized to construction costs, which decreased compared to $12 million in the same period in 2016 due to the completion of the Polk Power Station expansion in January 2017. Results reflect a 2.1% higher number of customers at June 30, 2017 compared to June 30, 2016.

Total degree days in Tampa Electric's service area in the year-to-date period of 2017 were 6% above normal and 4% 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 resulted in residential sales lower than last year. In the non-residential sectors, which are not as sensitive to heating degree days, energy sales were higher than last year. Total net energy for load increased 0.6% in the year-to-date 2017 period, compared with the same period in 2016. In the 2017 year-to-date period, pretax base revenues were $49 million higher than in 2016, driven by approximately $50 million pre-tax from higher base rates as 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 $4 million higher than in 2016,~~ reflecting increased efforts around customer service levels, transmission and distribution system reliability, and technology improvements. Depreciation and amortization expense increased $9 million in 2017, as the Polk unit was placed in service in January 2017 and from normal additions to facilities to reliably serve customers.

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.

Tampa Electric’s regulated operating statistics for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~ are as follows:

(millions, except customers and total degree days)		Operating Revenues								Kilowatt-hour sales								Operating Revenues								Kilowatt-hour sales
Three months ended June 30,		2017		2016			% Change			2017		2016		% Change
Three months ended March 31,																		2018			2017		% Change			2018		2017		% Change
By Customer Type
Residential		$	255	$	253			1			2,294		2,241		2			$	230		$	198		16			2,021		1,761		15
Commercial			149		148			1			1,636		1,565		5				132			131		1			1,404		1,431		(2	)
Industrial			39		40			(3	)		505		479		5				38			39		(3	)		473		504		(6	)
Other sales of electricity			41		43			(5	)		416		447		(7	)			44			37		19			448		386		16
Deferred and other revenues ⁽¹⁾			37		2		nm
Regulatory deferrals and unbilled revenue ⁽¹⁾																			(1	)		22	nm
Total energy sales			521		486			7			4,851		4,732		3				443			427		4			4,346		4,082		6
Sales for resale			5		0		nm				148		18		722				4			1		300			92		36		156
Other operating revenue			16		13			23											14			14		0
Total revenues		$	542	$	499			9			4,999		4,750		5			$	461		$	442		4			4,438		4,118		8
Customers at June 30, (thousands)			746		730			2
Customers at March 31, (thousands)																			751			743		1
Retail net energy for load (kilowatt hours)											5,376		5,262		2												4,480		4,261		5
Total degree days											1,377		1,255		10												700		553		27

Six months ended June 30,
By Customer Type
Residential		$	453	$	470			(4	)		4,055		4,155	��	(2	)
Commercial			280		280			0			3,067		2,953		4
Industrial			79		79			0			1,008		940		7
Other sales of electricity			77		83			(7	)		802		848		(5	)
Deferred and other revenues ⁽¹⁾			60		(17	)	nm
Total energy sales			949		895			6			8,932		8,896		0
Sales for resale			6		2			200			184		69		167
Other operating revenue			30		27			11
Total revenues		$	985	$	924			7			9,116		8,965		2
Customers at June 30, (thousands)			746		730			2
Retail net energy for load (kilowatt hours)											9,637		9,579		1
Total degree days											1,930		1,857		4

(1) Primarily reflects the timing of environmental and fuel clause recoveries.
(1) Primarily reflects the timing of clause recoveries.																	(1) Primarily reflects the timing of clause recoveries.
nm Not meaningful	nm Not meaningful																nm Not meaningful

PGS reported net income of ~~$10~~$15 million for the ~~second~~first quarter, compared with $7$14 million in the ~~2016 quarter.~~first quarter of 2017. Results reflect a 2.9% higher number of customers in the ~~second~~first quarter of ~~2017~~2018 compared to the ~~second~~first quarter of ~~2016. Therm sales to residential~~2017. Residential and commercial ~~customers~~revenue increased primarily ~~as a result of customer growth. Sales~~due to ~~commercial and industrial customers increased as a result of the stronger Florida economy and increased sales of compressed natural gas~~cooler weather compared to ~~vehicle fleets.~~ 2017.

Depreciation and amortization ~~decreased $1~~increased $2 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~~).

~~PGS reported net income of $23~~and normal asset growth. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $2 million ~~for~~higher than in the 2017 ~~year-to-date period, compared with $20 million in the 2016 period. These results reflect lower therm sales and related revenue as a result of the~~ ~~very mild winter, offset by $3 million lower~~ d~~epreciation and amortization expense~~quarter due to ~~the reasons in the quarter explanation above.~~higher employee-related costs, customer technology and contractor costs.

PGS’s regulated operating statistics for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~ are as follows:

(millions, except customers)	Operating Revenues							Therms							Operating Revenues						Therms
Three months ended June 30,	2017		2016		% Change			2017		2016		% Change
Three months ended March 31,															2018		2017		% Change		2018		2017		% Change
By Customer Type
Residential	$	31	$	31		0			16		15		7		$	56	$	42		33		35		28		25
Commercial		35		35		0			120		118		2			44		39		13		144		134		7
Industrial		3		3		0			81		78		4			4		4		0		90		87		3
Off system sales		17		18		(6	)		46		72		(36	)		15		10		50		36		27		33
Power generation		2		0					194		189		3			1		1		0		191		181		6
Other revenues		14		12		17										19		13		46
Total	$	102	$	99		3			457		472		(3	)	$	139	$	109		28		496		457		9
By Sales Type
System supply	$	56	$	58		(3	)		69		93		(26	)	$	83	$	61		36		78		61		28
Transportation		32		29		10			388		379		2			37		34		9		418		396		6
Other revenues		14		12		17										19		14		36
Total	$	102	$	99		3			457		472		(3	)	$	139	$	109		28		496		457		9
Customers at June 30, (thousands) ⁽¹⁾		375		364		3

Six months ended June 30,
By Customer Type
Residential	$	73	$	81		(10	)		44		48		(8	)
Commercial		74		77		(4	)		254		259		(2	)
Industrial		7		7		0			168		161		4
Off system sales		27		31		(13	)		74		126		(41	)
Power generation		3		2		50			374		380		(2	)
Other revenues		27		29		(7	)
Total	$	211	$	227		(7	)		914		974		(6	)
By Sales Type
System supply	$	118	$	133		(11	)		130		187		(30	)
Transportation		66		65		2			784		787		(0	)
Other revenues		27		29		(7	)
Total	$	211	$	227		(7	)		914		974		(6	)
Customers at June 30, (thousands) ⁽¹⁾		375		364		3
Customers at March 31, (thousands)																383		372		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.

For the second quarter 2017 and 2016, other income was $2 million and $7 million, respectively, and included AFUDC-equity of zero and $6 million, respectively. For year-to-date 2017 and 2016, other income was $5 million and $14 million, respectively, and included AFUDC-equity of $1 million and $12 million, respectively. The decrease in AFUDC-equity is due to Tampa Electric’s Polk Power Station expansion being placed in service in January 2017.

The provisions for income taxes for the three months ended March 31, 2018 and 2017 ~~and 2016 year-to-date periods~~ were ~~$89~~$14 million and ~~$78~~$35 million, respectively. The provision for income taxes for the ~~2017 year-to-date period increased~~2018 quarter decreased mainly due to ~~higher pre-tax income and lower~~ tax ~~benefits related~~reform impacts. See Note 4 to ~~AFUDC-equity and production deduction.~~the TEC Consolidated Condensed Financial Statements for further information.

The table below sets forth the ~~June 30, 2017~~March 31, 2018 liquidity, cash balances and amounts available under the TEC credit facilities.


(millions)
Credit facilities	$	475	$	775
Drawn amounts/letters of credit ⁽¹⁾		299		301
Available credit facilities		176		474
Cash and short-term investments		15		16
Total liquidity	$	191	$	490

Cash flows from operating activities for the ~~six~~three months ended ~~June 30, 2017 was $228~~March 31, 2018 were $157 million, ~~a decrease~~an increase of ~~$235~~$81 million compared to the same period in ~~2016.~~2017. The ~~decrease~~increase is primarily due to lower payments in ~~2017 related to significant December 2016 accruals~~2018 for products and ~~services;~~services, increased collections in 2018 of first quarter revenues and year-end receivables, and fewer refunds ~~to retail customers~~associated with over-recovered clause recoveries in ~~2017 for fuel clause over-recoveries collected in 2016; and lower fuel clause over-recoveries collected in 2017.~~2018.

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, 2017,~~March 31, 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, 2017.~~March 31, 2018. Reference is made to the specific agreements and instruments for more details.

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.

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, certainCertain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 1011 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, 2017.~~March 31, 2018.

~~On January 16, 2017,~~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 ~~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~~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 other generation investments. TEC intends to fund those capital expenditures ~~shown below are based~~with available cash on ~~current estimates~~hand, cash generated from operating activities, and ~~assumptions.~~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 ~~from these estimates~~ due to changes in schedule, costs for materials or labor or changes in plans.

All natural gas derivatives were entered into by ~~the regulated utilities~~TEC to manage the impact of natural gas prices on ~~customers.~~ 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 ~~hedging~~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 1112 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, 2017,~~March 31, 2018, the fair value of derivatives was not materially affected by nonperformance risk.

~~TEC’s critical~~Critical accounting policies ~~relate to deferred income taxes, employee postretirement benefits~~ and ~~regulatory accounting.~~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, ~~2016.~~2017.

~~Changes in Fair Value~~Information required by Item 3 is omitted pursuant to General Instruction H(2) 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 6% from December 31, 2016 to June 30, 2017. TEC decreased the natural gas volume hedged as of June 30, 2017 as compared to December 31, 2016 by 51%.

~~The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the six-month period ended June 30, 2017:~~

~~Below is a summary table of sources of fair value, by maturity period, for derivative contracts at June 30, 2017:~~

~~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.~~

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 ~~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.

~~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.~~

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
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
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
~~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)
MWH		megawatt-hour(s)
NAESB		North American Energy Standards Board

Term		Meaning
~~NAESB~~NAV		~~North American Energy Standards Board~~
~~NAV~~		net asset value
~~NMGC~~		~~New Mexico Gas Company, Inc.~~
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
~~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
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

			Calculation at
Instrument	Financial Covenant ⁽¹⁾	Requirement/Restriction	~~June 30, 2017~~March 31, 2018
Credit facility - $325 million ⁽²⁾	Debt/capital	Cannot exceed 65%	44.6%	~~46.3%~~
Credit facility - $300 million ⁽²⁾	Debt/capital	Cannot exceed 65%	44.6%
Accounts receivable credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		~~46.3%~~44.6%

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

Net fair value of derivatives as of December 31, 2016	$	17
Additions and net changes in unrealized fair value of derivatives		(13	)
Realized net settlement of derivatives		(3	)
Net fair value of derivatives as of June 30, 2017	$	1

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2017		0		9
2018		0		7
Total		0		16

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

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

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

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		(13	)
Realized net settlement of derivatives		(3	)
Net fair value of derivatives as of June 30, 2017	$	1

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

	~~TAMPA ELECTRIC COMPANY~~
	~~(Registrant)~~

~~Date: August 10, 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)~~

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	Amendment No. 2 dated as of March 23, 2018 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 8-K dated March 23, 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: May 10, 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)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company