ck0000096271-10q_20190630.htm

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit 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 8, 2019, 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 in 2018 and 2019 include the following:

Term		Meaning
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
AMI		Advanced Metering Infrastructure
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
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)
IGCC		integrated gasification combined-cycle
IOU		investor owned utility
IRS		Internal Revenue Service
ITCs		investment tax credits
KW		kilowatt(s)
kWac		kilowatt on an alternating current basis
LNG		liquefied natural gas
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
MMBTU		one million British Thermal Units
MRV		market-related value
MW		megawatt(s)
MWH		megawatt-hour(s)
NAV		net asset value
Note		Note to consolidated financial statements
NO_x		nitrogen oxide
NPNS		normal purchase normal sale
NYMEX		New York Mercantile Exchange
O&M expenses		operations and maintenance expenses
OCI		other comprehensive income

Assets	June 30,			December 31,
(millions)	2019			2018
Property, plant and equipment
Utility plant
Electric	$	10,064		$	9,645
Gas		1,888			1,793
Utility plant, at original costs		11,952			11,438
Accumulated depreciation		(3,350	)		(3,214	)
Utility plant, net		8,602			8,224
Other property		13			12
Total property, plant and equipment, net		8,615			8,236

Current assets
Cash and cash equivalents		10			15
Receivables, less allowance for uncollectibles of $2 at June 30, 2019 and December 31, 2018		256			258
Due from affiliates		13			4
Inventories, at average cost
Fuel		41			46
Materials and supplies		104			100
Regulatory assets		88			88
Prepayments and other current assets		12			6
Total current assets		524			517

Deferred debits
Regulatory assets		388			370
Other		45			32
Total deferred debits		433			402
Total assets	$	9,572		$	9,155

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

Liabilities and Capitalization	June 30,			December 31,
(millions)	2019			2018
Capitalization
Common stock	$	3,210		$	2,990
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		345			314
Total capital		3,554			3,303
Long-term debt		2,575			2,575
Total capitalization		6,129			5,878

Current liabilities
Notes payable		386			221
Accounts payable		205			251
Due to affiliates		20			24
Customer deposits		132			132
Regulatory liabilities		80			44
Accrued interest		15			16
Accrued taxes		51			13
Other		40			84
Total current liabilities		929			785

Long-term liabilities
Deferred income taxes		740			799
Regulatory liabilities		1,252			1,266
Investment tax credits		170			74
Deferred credits and other liabilities		352			353
Total long-term liabilities		2,514			2,492

Commitments and Contingencies (see Note 8)

Total liabilities and capitalization	$	9,572		$	9,155

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

	Three months ended June 30,
(millions)	2019			2018
Revenues
Electric	$	520		$	509
Gas		107			110
Total revenues		627			619
Expenses
Fuel		139			133
Purchased power		13			14
Cost of natural gas sold		38			39
Operations and maintenance		132			162
Depreciation and amortization		94			89
Taxes, other than income		52			51
Total expenses		468			488
Income from operations		159			131
Other income
Allowance for equity funds used during construction		2			1
Other income, net		3			2
Total other income		5			3
Interest charges
Interest expense		34			30
Allowance for borrowed funds used during construction		(1	)		(1	)
Total interest charges		33			29
Income before provision for income taxes		131			105
Provision for income taxes		24			20
Net income	$	107		$	85
Other comprehensive income, net of tax
Gain on cash flow hedges		0			1
Comprehensive income	$	107		$	86

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

	Six months ended June 30,
(millions)	2019			2018
Revenues
Electric	$	931		$	970
Gas		235			246
Total revenues		1,166			1,216
Expenses
Fuel		246			255
Purchased power		17			27
Cost of natural gas sold		85			94
Operations and maintenance		262			319
Depreciation and amortization		186			182
Taxes, other than income		102			103
Total expenses		898			980
Income from operations		268			236
Other income
Allowance for equity funds used during construction		4			1
Other income, net		5			4
Total other income		9			5
Interest charges
Interest expense		68			60
Allowance for borrowed funds used during construction		(2	)		(1	)
Total interest charges		66			59
Income before provision for income taxes		211			182
Provision for income taxes		40			34
Net income	$	171		$	148
Other comprehensive income, net of tax
Gain on cash flow hedges		0			1
Comprehensive income	$	171		$	149

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

	Six months ended June 30,
(millions)	2019			2018
Cash flows from operating activities
Net income	$	171		$	148
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		186			182
Deferred income taxes and investment tax credits		31			14
Deferred recovery clauses		1			(25	)
Inventories		1			5
Prepayments and other deposits		(6	)		(2	)
Taxes accrued		25			28
Accounts payable		(54	)		(37	)
Regulatory assets and liabilities		5			54
Other		(29	)		(21	)
Cash flows from operating activities		331			346
Cash flows used in investing activities
Capital expenditures		(581	)		(510	)
Cash flows used in investing activities		(581	)		(510	)
Cash flows from financing activities
Equity contributions from Parent		220			215
Proceeds from long-term debt issuance		0			345
Repayment of long-term debt		0			(304	)
Net increase in short-term debt		165			70
Dividends to Parent		(140	)		(160	)
Cash flows from financing activities		245			166
Net increase (decrease) in cash and cash equivalents		(5	)		2
Cash and cash equivalents at beginning of period		15			13
Cash and cash equivalents at end of period	$	10		$	15
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(4	)	$	18

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

								Accumulated
								Other
			Common		Retained			Comprehensive			Total
(millions, except share amounts)	Shares		Stock		Earnings			Loss			Capital
Three months ended June 30, 2019
Balance, March 31, 2019		10		3,100	$	302		$	(1	)	$	3,401
Net income						107						107
Equity contributions from Parent			110									110
Dividends to Parent						(64	)					(64	)
Balance, June 30, 2019		10	$	3,210	$	345		$	(1	)	$	3,554

Three months ended June 30, 2018
Balance, March 31, 2018		10		2,755	$	301		$	(2	)	$	3,054
Net income						85						85
Other comprehensive income, after tax									1			1
Equity contributions from Parent			105									105
Dividends to Parent						(63	)					(63	)
Balance, June 30, 2018		10	$	2,860	$	323		$	(1	)	$	3,182

Six months ended June 30, 2019
Balance, December 31, 2018		10		2,990	$	314		$	(1	)	$	3,303
Net income						171						171
Equity contributions from Parent			220									220
Dividends to Parent						(140	)					(140	)
Balance, June 30, 2019		10	$	3,210	$	345		$	(1	)	$	3,554

Six months ended June 30, 2018
Balance, December 31, 2017		10		2,645	$	335		$	(2	)	$	2,978
Net income						148						148
Other comprehensive income, after tax									1			1
Equity contributions from Parent			215									215
Dividends to Parent						(160	)					(160	)
Balance, June 30, 2018		10	$	2,860	$	323		$	(1	)	$	3,182

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, 2018 for a complete discussion of accounting policies. The significant accounting policies for TEC include:

TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS.

Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2019 and December 31, 2018, and the results of operations and cash flows for the periods ended June 30, 2019 and June 30, 2018. The results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2019.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $254 million and $226 million as of June 30, 2019 and December 31, 2018, 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, fuel prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

As of June 30, 2019 and December 31, 2018, unbilled revenues of $75 million and $67 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-for-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 $28 million for the three months ended June 30, 2019 and 2018, respectively, and $56 million and $57 million for the six months ended June 30, 2019 and 2018, respectively.

The new U.S. GAAP accounting policies that are applicable to and adopted by TEC in 2019 are described as follows:

On January 1, 2019, TEC adopted Accounting Standard Updates (ASU) 2016-02, Leases (Topic 842), including all related amendments, using the modified retrospective approach. The standard requires lessees to recognize leases on the balance sheet for all leases with a term of longer than twelve months and disclose key information about leasing arrangements.

As permitted by the optional transition method, TEC did not restate comparative financial information in its consolidated financial statements, did not reassess whether any expired or existing contracts contained leases and carried forward existing lease classifications. Additionally, TEC elected to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under the leasing guidance within ASC Topic 840. TEC elected to use hindsight to determine the lease term for existing leases and elected to not separate lease components from non-lease components for all lessee and lessor arrangements.

TEC has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. There were no updates to information technology systems as a result of implementation.

TEC’s adoption of this new standard resulted in right-of-use (ROU) assets and lease liabilities of $20 million as of January 1, 2019. The ROU assets and lease liabilities were measured at the present value of remaining lease payments using TEC’s incremental borrowing rate.

There was no impact to opening retained earnings as of January 1, 2019 or TEC’s net income or cash flows for the three and six months ended June 30, 2019 as a result of the adoption of the standard. There were no significant impacts to TEC’s accounting for lessor arrangements. Refer to Note 11 for further detail.

On January 1, 2019, TEC adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. There was no impact on the condensed consolidated financial statements as a result of the adoption of this standard.

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. TEC early adopted the standard effective January 1, 2019 and elected to apply the guidance prospectively. There was no material impact on the condensed consolidated financial statements as a result of the adoption of this standard.

TEC considers the applicability and impact of all ASUs issued by the FASB. The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in TEC’s Annual Report on Form 10-K for the year ended December 31, 2018.

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

The amended agreement provides for SoBRAs for TEC’s investments in solar generation. Tampa Electric plans to invest approximately $850 million during 2017 through 2021 related to 600 MW of solar projects recoverable under the SoBRAs.

On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018 and TEC began receiving these revenues in January 2019. On June 28, 2019, TEC filed its third SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2020 tranche representing 149 MW and $27 million annually in estimated revenue requirements. The FPSC is expected to issue its decision regarding the third SoBRA in the fourth quarter of 2019.

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs and to replenish the balance in the reserve to the level that existed as of October 31, 2013.

On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addressed both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) while keeping customer rates stable in 2018. Beginning on April 1, 2018, the agreement authorized Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits of $103 million. As a result, during 2018, Tampa Electric recorded O&M expense and a reduction of the storm reserve regulatory asset of $47 million and recorded O&M expense for the increase in the storm reserve regulatory liability of $56 million to reflect effective recovery of the storm costs due to the allowed netting of storm cost recovery with tax reform benefits. On August 20, 2018, the FPSC approved lowering base rates by $103 million annually beginning on January 1, 2019 as a result of lower tax expense.

On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric will refund $12 million to customers in January 2020, resulting in minimal impact to the Consolidated Condensed Statements of Income.

PGS’s base rates were established in 2009. In 2017, the FPSC approved an updated PGS settlement agreement that did not contain a provision for tax reform. In 2018, the FPSC approved a settlement agreement authorizing PGS to accelerate $11 million of amortization of its regulatory asset associated with the MGP environmental liability in 2018 to net it against the estimated 2018 tax reform benefits.

In accordance with the 2018 settlement agreement, PGS reduced its base rates by $12 million for the impact of tax reform and reduced depreciation rates by $10 million on an annual basis beginning in January 2019. PGS is permitted to initiate a general base rate proceeding during 2020 regardless of its earned ROE at the time provided the new rates do not become effective before January 1, 2021.

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

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

Regulatory Assets and Liabilities
(millions)	June 30, 2019		December 31, 2018
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	73	$	56
Cost-recovery clauses ⁽²⁾		61		55
Environmental remediation⁽³⁾		25		23
Postretirement benefits ⁽⁴⁾		288		295
Storm reserve ⁽⁵⁾		3		3
Other		26		26
Total regulatory assets		476		458
Less: Current portion		88		88
Long-term regulatory assets	$	388	$	370
Regulatory liabilities:
Regulatory tax liability⁽⁶⁾	$	725	$	715
Cost-recovery clauses ⁽²⁾		24		17
Accumulated reserve - cost of removal⁽⁷⁾		512		513
Storm reserve ⁽⁸⁾		56		56
Other		15		9
Total regulatory liabilities		1,332		1,310
Less: Current portion		80		44
Long-term regulatory liabilities	$	1,252	$	1,266

On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of tax reform changes affecting businesses, effective January 1, 2018 which provide a corporate federal tax rate reduction from 35% to 21%, 100% asset expensing, limitation of interest deduction, the repeal of section 199 domestic production deduction and the

preservation of the existing normalization rules. The Act also provides that regulated electric and gas companies are exempt from the 100% asset expensing and interest expense deduction limitation. In accordance with U.S. GAAP, TEC was required to revalue its deferred income tax assets and liabilities based on the new 21% federal tax rate at the date of enactment. Additionally, under FPSC rules TEC was required to adjust deferred income tax assets and liabilities for changes in tax rates with a corresponding regulatory liability for the excess deferred taxes generated by the tax rate differential. See Note 3.

TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements with TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is reflected in common stock.

TEC’s effective tax rates for the six months ended June 30, 2019 and 2018 were 19.0% and 18.7%, respectively. The June 30, 2019 effective tax rate is an estimate of the annual effective income tax rate. TEC’s effective tax rate for the six months ended June 30, 2019 and 2018 differed from the statutory rate principally due to the amortization of the regulatory tax liability resulting from tax reform. See Note 3 for further information regarding the regulatory tax liability.

As of June 30, 2019 and December 31, 2018, the amount of unrecognized tax benefits was $8 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC believes that the total unrecognized tax benefits will decrease and be recognized within the next twelve months due to the ongoing audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. TEC had $8 million of unrecognized tax benefits at June 30, 2019 and December 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 and Restoration Plan.

TECO Energy Benefit Cost
(millions)	Pension Benefits								Other Postretirement Benefits
Three months ended June 30,	2019				2018				2019		2018
Components of net periodic benefit cost
Service cost	$	5			$	6			$	0	$	0
Interest cost		8				7				1		2
Expected return on assets		(14	)			(12	)			0		0
Amortization of:
Prior service (benefit) cost		0				0				0		1
Actuarial (gain) loss		5				4				0		(1	)
Settlement cost		0				2		⁽¹⁾		0		0
Net periodic benefit cost	$	4			$	7			$	1	$	2
Six months ended June 30,
Components of net periodic benefit cost
Service cost	$	10			$	11			$	0	$	1
Interest cost		16				14				3		4
Expected return on assets		(26	)			(24	)			0		0
Amortization of:
Actuarial (gain) loss		8				9				0		(1	)
Settlement cost		1		⁽¹⁾		2		⁽¹⁾		0		0
Net periodic benefit cost	$	9			$	12			$	3	$	4

(1)Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the prior retirements of certain executives.

TEC’s portion of the net periodic benefit cost for the three months ended June 30, 2019 and 2018, respectively, was $3 million and $6 million for pension benefits, and $1 million and $2 million for other postretirement benefits. TEC’s portion of the net periodic

benefit cost for the six months ended June 30, 2019 and 2018, respectively, was $7 million and $9 million for pension benefits, and $3 million and $4 million for other postretirement benefits.

TECO Energy assumed a long-term EROA of 7.35% and a discount rate of 4.34% for pension benefits under its qualified pension plan for 2019. For TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.38% for 2019.

TECO Energy made contributions of $7 million and $10 million to its qualified pension plan in the six months ended June 30, 2019 and 2018, respectively. TEC’s portion of these contributions was $5 million and $8 million, respectively. TECO Energy expects to make contributions to the pension plan of $14 million for the remainder of 2019, and TEC estimates its portion of the remaining 2019 contributions to be $10 million.

Included in the benefit cost discussed above, for the three and six months ended June 30, 2019, TEC reclassified $3 million and $6 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses from regulatory assets to the Consolidated Condensed Statement of Income, compared with $4 million and $8 million for the three and six months ended June 30, 2018, respectively.

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


	June 30, 2019						December 31, 2018
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325	$	275	$	1	$	325	$	131	$	1
3-year accounts receivable facility ⁽³⁾		150		111		0		150		90		0
Total	$	475	$	386	$	1	$	475	$	221	$	1

At June 30, 2019, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at June 30, 2019 and December 31, 2018 was 3.36% and 3.14%, respectively.

At June 30, 2019, TEC’s long-term debt had a carrying amount of $2,575 million and an estimated fair market value of $2,903 million. At December 31, 2018, TEC’s total long-term debt had a carrying amount of $2,575 million and an estimated fair market value of $2,686 million. The fair value of the debt securities is determined using Level 2 measurements (see Note 13 for information regarding the fair value hierarchy).

On July 24, 2019, TEC completed a sale of $300 million aggregate principal amount of 3.625% unsecured notes due June 15, 2050. Until December 15, 2049, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2049, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss.

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of June 30, 2019, TEC has estimated its ultimate financial liability to be $28 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s currently assessed percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

TEC has commitments for purchased power, long-term leases, other purchase obligations, long-term service agreements and capital projects. In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at June 30, 2019:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total

2019	$	23	$	100	$	246	$	125	$	3	$	1	$	2	$	500
2020		0		196		86		33		6		2		1		324
2021		0		191		35		3		7		2		0		238
2022		0		184		9		3		7		2		0		205
2023		0		161		3		1		11		2		0		178
Thereafter		0		1,647		13		0		78		35		0		1,773
Total future minimum payments	$	23	$	2,479	$	392	$	165	$	112	$	44	$	3	$	3,218

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements and has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2019, TEC was in compliance with all required financial covenants.

(millions)	Tampa								Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations				Company
2019
Revenues - external	$	520	$	107	$	0			$	627
Intracompany sales		1		4		(5	)			0
Total revenues		521		111		(5	)			627
Total interest charges		29		4		0				33
Net income	$	93	$	14	$	0			$	107
2018
Revenues - external	$	509	$	110	$	0			$	619
Intracompany sales		1		5		(6	)			0
Total revenues		510		115		(6	)			619
Total interest charges		25		4		0				29
Net income	$	74	$	11	$	0			$	85
Six months ended June 30,
2019
Revenues - external	$	931	$	235	$	0			$	1,166
Intracompany sales		2		8		(10	)			0
Total revenues		933		243		(10	)			1,166
Total interest charges		58		8		0				66
Net income	$	139	$	32	$	0			$	171
2018
Revenues - external	$	970	$	246	$	0			$	1,216
Intracompany sales		1		11		(12	)			0
Total revenues		971		257		(12	)			1,216
Total interest charges		51		8		0				59
Net income	$	121	$	27	$	0			$	148
Total assets at June 30, 2019	$	8,674	$	1,478	$	(580	)	⁽¹⁾	$	9,572
Total assets at December 31, 2018	$	8,235	$	1,407	$	(487	)	⁽¹⁾	$	9,155

(millions)	Tampa							Tampa Electric
Three months ended June 30, 2019	Electric		PGS		Eliminations			Company
Electric revenue
Residential	$	261	$	0	$	0		$	261
Commercial		141		0		0			141
Industrial		42		0		0			42
Regulatory deferrals and unbilled revenue		17		0		0			17
Other ⁽¹⁾		60		0		(1	)		59
Total electric revenue		521		0		(1	)		520
Gas revenue
Residential		0		36		0			36
Commercial		0		35		0			35
Industrial ⁽²⁾		0		6		0			6
Other ⁽³⁾		0		34		(4	)		30
Total gas revenue		0		111		(4	)		107
Total revenue	$	521	$	111	$	(5	)	$	627
Three months ended June 30, 2018
Electric revenue

Residential	$	241	$	0	$	0		$	241
Commercial		140		0		0			140
Industrial		40		0		0			40
Regulatory deferrals and unbilled revenue		24		0		0			24
Other ⁽¹⁾		65		0		(1	)		64
Total electric revenue		510		0		(1	)		509
Gas revenue
Residential		0		35		0			35
Commercial		0		37		0			37
Industrial ⁽²⁾		0		6		0			6
Other ⁽³⁾		0		37		(5	)		32
Total gas revenue		0		115		(5	)		110
Total revenue	$	510	$	115	$	(6	)	$	619

(millions)	Tampa							Tampa Electric
Six months ended June 30, 2019	Electric		PGS		Eliminations			Company
Electric revenue
Residential	$	467	$	0	$	0		$	467
Commercial		261		0		0			261
Industrial		76		0		0			76
Regulatory deferrals and unbilled revenue		10		0		0			10
Other ⁽¹⁾		119		0		(2	)		117
Total electric revenue		933		0		(2	)		931
Gas revenue
Residential		0		86		0			86
Commercial		0		77		0			77
Industrial ⁽²⁾		0		11		0			11
Other ⁽³⁾		0		69		(8	)		61
Total gas revenue		0		243		(8	)		235
Total revenue	$	933	$	243	$	(10	)	$	1,166
Six months ended June 30, 2018
Electric revenue
Residential	$	471	$	0	$	0		$	471
Commercial		272		0		0			272
Industrial		78		0		0			78
Regulatory deferrals and unbilled revenue		23		0		0			23
Other ⁽¹⁾		127		0		(1	)		126
Total electric revenue		971		0		(1	)		970
Gas revenue
Residential		0		91		0			91
Commercial		0		81		0			81
Industrial ⁽²⁾		0		11		0			11
Other ⁽³⁾		0		74		(11	)		63
Total gas revenue		0		257		(11	)		246
Total revenue	$	971	$	257	$	(12	)	$	1,216

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of June 30, 2019 and December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $131 million and $135 million, respectively. As allowed under 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.

TEC determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

Operating lease ROU assets and operating lease liabilities are recognized on the Consolidated Condensed Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of TEC’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operations and maintenance expenses” on the Consolidated Condensed Statements of Income.

Where TEC is the lessor, a lease is a sales-type lease if certain criteria is met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

TEC has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases.

TEC has operating leases for buildings, land, telecommunication services and rail cars. TEC’s leases have remaining lease terms of 2 years to 67 years, some of which include options to extend the leases for up to an additional 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.

TEC has recorded operating lease expense for the three and six months ended June 30, 2019 of $1 million and $2 million, respectively.

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at June 30, 2019:

TEC leases CNG stations to other companies, which are classified as direct finance leases. The net investment in direct finance leases consists of the following:

The unearned income related to these direct finance leases is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Gas revenues” on the Consolidated Condensed Statements of Income. Customers have the option to purchase the assets related to the CNG stations at any time after 2021 by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. Alternatively, the customer may take possession of the CNG station asset at the end of the lease term for no cost.

As of June 30, 2019, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following:

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

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers and to optimize the utilization of its physical natural gas storage capacity and firm transportation capacity on interstate pipelines.

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.

On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which replaces the existing 2013 base rate settlement agreement and includes a provision for a five-year moratorium on hedging of natural gas purchases ending on December 31, 2022 (see Note 3). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had $1 million of derivative liabilities related to natural gas storage and transportation optimization as of June 30, 2019 and zero derivative assets and liabilities on its Consolidated Condensed Balance Sheets as of December 31, 2018.

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 and to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage and firm transportation capacity for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income.

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, 2019, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected.

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices or other circumstances 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, 2019, counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies, collateralized, or approved for credit based on their financial statements. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

As of June 30, 2019 and December 31, 2018, 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.

On July 24, 2019, TEC completed a sale of $300 million aggregate principal amount of 3.625% unsecured notes due June 15, 2050. See Note 7 for additional information.

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, 2018.

		Three months ended June 30,						Six months ended June 30,
(millions)		2019			2018			2019			2018
Revenues
	Tampa Electric	$	521		$	510		$	933		$	971
	PGS		111			115			243			257
	Eliminations		(5	)		(6	)		(10	)		(12	)
	TEC	$	627		$	619		$	1,166		$	1,216

Net income
	Tampa Electric	$	93		$	74		$	139		$	121
	PGS		14			11			32			27
	TEC	$	107		$	85		$	171		$	148

Second quarter 2019 net income was $107 million, compared to $85 million in the second quarter of 2018. In the second quarter of 2018, as permitted by the FPSC, TEC offset the impact of estimated 2018 tax reform benefits with a $32 million charge to O&M expense related to storm costs, comprised of $30 million at Tampa Electric and $2 million at PGS (see Note 3 to the TEC Consolidated Condensed Financial Statements). Beginning on January 1, 2019, as approved by the FPSC, base rates were lowered due to the impact of tax reform by an estimated $103 million annually ($25 million in the second quarter of 2019) at Tampa Electric and $12 million annually ($2 million in the second quarter of 2019) at PGS. Therefore, the decrease in revenue due to lower base rates from tax reform in 2019 was largely offset by lower O&M expense from the absence of the offsetting of tax reform benefits in 2018, resulting in minimal impact to the Consolidated Condensed Statements of Income. Excluding the impact of tax reform and storm costs, second quarter 2019 results were impacted by higher revenue primarily related to the in-service of solar generation projects, customer growth and weather, partially offset by higher depreciation expense and higher interest expense. See below for further detail.

Year-to-date 2019 net income was $171 million, compared to $148 million in the 2018 year-to-date period. Year-to-date 2018, as permitted by the FPSC, TEC offset the impact of estimated 2018 tax reform benefits with a $53 million charge to O&M expense related to storm costs, comprised of $48 million at Tampa Electric and $5 million at PGS (see Note 3 to the TEC Consolidated Condensed Financial Statements). Beginning on January 1, 2019, as approved by the FPSC, base rates were lowered due to the impact of tax reform by $103 million annually ($47 million in the six months ended June 30, 2019) at Tampa Electric and $12 million annually ($5 million in the six months ended June 30, 2019) at PGS. Therefore, the decrease in revenue due to lower base rates from tax reform in 2019 was largely offset by lower O&M expense from the absence of the offsetting of tax reform benefits in 2018, resulting in minimal impact to the Consolidated Condensed Statements of Income. Excluding the impact of tax reform and storm costs, year-to-date 2019 results were impacted by higher base revenue primarily related to the in-service of solar generation projects and customer growth and higher AFUDC earnings, partially offset by lower clause revenue, higher depreciation expense and higher interest expense. See below for further detail.

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

Tampa Electric’s net income for the second quarter of 2019 was $93 million, compared with $74 million for the same period in 2018. Excluding the impact of tax reform and storm costs as disclosed above, results primarily reflected higher base revenues and clause revenues, partially offset by higher depreciation expense and higher interest expense. Base revenues are energy sales excluding revenues from clauses, gross receipts taxes and franchise fees. Clauses, gross receipts taxes and franchise fees do not have a material effect on net income as these revenues substantially represent a dollar-for-dollar recovery of clauses and other pass-through costs.

Excluding the impact of tax reform as disclosed above, revenues were $35 million higher than in the same period in 2018, driven by higher base revenues and clause revenues related to the in-service of solar generation projects, customer growth, and weather. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in the second quarter of 2019 were 11% above normal and 8% above the 2018 period. Total retail net energy for load, which is a calendar measurement of energy output, increased 6.0% in the second quarter of 2019 compared with the same period in 2018 due to warmer weather. Results also reflect a 1.9% increase in number of customers at June 30, 2019 compared to June 30, 2018.

O&M expense, excluding all FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement regarding tax reform and storm costs, was $3 million higher than in the 2018 quarter, primarily reflecting higher line clearance and pole inspection activities. See Note 3 to the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and storm settlement agreement. Depreciation and amortization expense increased $6 million in the second quarter of 2019 from normal additions to facilities to reliably serve customers and the in-service of solar generation projects.

Tampa Electric’s net income year-to-date 2019 was $139 million, compared with $121 million for the same period in 2018. Excluding the impact of tax reform and storm costs as disclosed above, results reflected higher base revenues and higher AFUDC earnings, partially offset by lower clause revenue, higher depreciation expense and higher interest expense.

Excluding the impact of tax reform as disclosed above, revenues were $9 million higher than in the same period in 2018, driven by in-service of solar generation projects and customer growth, partially offset by lower clause revenue. Total degree days in Tampa Electric's service area in the year-to-date period of 2019 were 7% above normal and 1% below the 2018 period. Total net energy for load increased 1.6% in the year-to-date period of 2019 compared with the same period in 2018.

In the 2019 year-to-date period, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement regarding tax reform and storm costs, was $2 million lower than in the 2018 year-to-date period primarily reflecting the timing of generation outages, partially offset by higher line clearance and pole inspection activities. See Note 3 to the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and storm settlement agreement. Depreciation and amortization expense increased $11 million in 2019 from normal additions to facilities to reliably serve customers and the in-service of solar generation projects.

Tampa Electric’s regulated operating statistics for the three and six months ended June 30, 2019 and 2018 were as follows:

(millions, except customers and total degree days)	Operating Revenues							Kilowatt-Hours Billed
Three months ended June 30,	2019		2018		% Change			2019		2018		% Change
By Customer Type
Residential ⁽¹⁾	$	261	$	241		8			2,366		2,133		11
Commercial ⁽¹⁾		141		140		1			1,543		1,503		3
Industrial ⁽¹⁾		42		40		5			539		505		7
Other ⁽¹⁾		45		46		(2	)		476		473		1
Regulatory deferrals and unbilled revenue ⁽²⁾		17		24		(29	)
Total retail sales of electricity		506		491		3			4,924		4,614		7
Off system sales of electricity		1		4		(75	)		30		113		(73	)
Other operating revenue		14		15		(7	)
Total revenues	$	521	$	510		2			4,954		4,727		5
Customers at June 30, (thousands)		771		757		2
Retail net energy for load (kilowatt hours)		5,581		5,262		6
Total degree days		1,376		1,279		8

Six months ended June 30,
By Customer Type
Residential ⁽¹⁾	$	467	$	471		(1	)		4,305		4,154		4
Commercial ⁽¹⁾		261		272		(4	)		2,913		2,907		0
Industrial ⁽¹⁾		76		78		(3	)		1,001		978		2
Other ⁽¹⁾		86		90		(4	)		922		921		0
Regulatory deferrals and unbilled revenue ⁽²⁾		10		23		(57	)
Total retail sales of electricity		900		934		(4	)		9,141		8,960		2
Off system sales of electricity		2		8		(75	)		45		205		(78	)
Other operating revenue		31		29		7
Total revenues	$	933	$	971		(4	)		9,186		9,165		0
Customers at June 30, (thousands)		771		757		2
Retail net energy for load (kilowatt-hours)		9,902		9,742		2
Total degree days		1,962		1,979		(1	)

PGS had net income of $14 million for the second quarter, compared with $11 million in the second quarter of 2018. Results reflect a 3.1% higher number of customers in the second quarter of 2019 compared to the second quarter of 2018. Excluding the impact of tax reform as disclosed above, revenues were $1 million lower than the prior year quarter due to lower off-system sales. Excluding the impact of tax reform as disclosed above, base revenues were consistent with 2018 primarily due to customer growth being offset by warmer spring weather in 2019. Depreciation and amortization decreased $2 million due to reduced depreciation rates in 2019 related to the settlement agreement, which was partially offset by normal asset growth. Return on investment in cast iron and bare steel replacement rider was $1 million higher in the 2019 period.

PGS had net income of $32 million for the 2019 year-to-date period, compared with $27 million in the 2018 period. Excluding the impact of tax reform as disclosed above, revenues were $8 million lower than the prior year quarter due to lower clause-related revenue and lower off-system sales. Excluding the impact of tax reform as disclosed above, base revenues were $1 million higher than 2018 primarily due to customer growth being partially offset by warmer weather in 2019. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of deferring tax reform benefits in 2018, was $1 million higher than in 2018 primarily due to higher employee benefit and self-insurance costs. Depreciation and amortization decreased $8 million due to accelerated amortization of the regulatory asset associated with MGP environmental remediation costs in 2018 and reduced depreciation rates in 2019 related to the settlement agreement, which were partially offset by normal asset growth. Return on investment in cast iron and bare steel replacement rider was $2 million higher in the 2019 period. Interest expense increased $1 million due to higher long-term debt levels related to funding asset growth.

PGS’s regulated operating statistics for the three and six months ended June 30, 2019 and 2018 were as follows:

(millions, except customers)	Operating Revenues							Therms
Three months ended June 30,	2019		2018		% Change			2019		2018		% Change
By Customer Type
Residential	$	36	$	35		3			18		18		0
Commercial		35		37		(5	)		122		125		(2	)
Industrial		4		4		0			105		88		19
Power generation		2		2		0			229		179		28
Off system sales		14		16		(13	)		50		50		0
Other operating revenues		16		17		(6	)
Total	$	107	$	111		(4	)		524		460		14
By Sales Type
System supply	$	60	$	61		(2	)		73		74		(1	)
Transportation		31		33		(6	)		451		386		17
Other operating revenues		16		17		(6	)
Total	$	107	$	111		(4	)		524		460		14
Customers at June 30, (thousands)		397		386		3

Six months ended June 30,
By Customer Type
Residential	$	86	$	91		(5	)		51		53		(4	)
Commercial		77		81		(5	)		268		269		(0	)
Industrial		8		8		0			210		178		18
Power generation		3		3		0			417		370		13
Off system sales		27		31		(13	)		87		86		1
Other operating revenues		36		36		0
Total	$	237	$	250		(5	)		1,033		956		8
By Sales Type
System supply	$	134	$	144		(7	)		149		152		(2	)
Transportation		67		70		(4	)		884		804		10
Other operating revenues		36		36		0
Total	$	237	$	250		(5	)		1,033		956		8
Customers at June 30, (thousands)		397		386		3

For the second quarter of 2019 and 2018, TEC’s other income was $5 million and $3 million, respectively, and included AFUDC-equity of $2 million and $1 million, respectively. For the year-to-date periods in 2019 and 2018, TEC’s other income was $9 million and $5 million, respectively, and included AFUDC-equity of $4 million and $1 million, respectively. The increase in AFUDC-equity is due to Tampa Electric’s construction of solar generation, AMI and the Big Bend modernization project as disclosed in Capital Investments below.

For the second quarter of 2019 and 2018, TEC’s interest expense, excluding AFUDC-debt, was $34 million and $30 million, respectively. For the year-to-date periods in 2019 and 2018, TEC’s interest expense, excluding AFUDC-debt, was $68 million and $60 million, respectively. The increase is due to higher short-term interest rates and an increase in long-term borrowings.

The provisions for income taxes for the six months ended June 30, 2019 and 2018 were $40 million and $34 million, respectively. The provision for income taxes for the 2019 period increased mainly due to higher pre-tax income.

During the 2019 legislative session, the Florida legislature passed, and the governor signed, a bill that creates a new cost recovery clause, called the storm protection cost recovery clause. This new clause establishes a process for Florida investor-owned utilities to recover transmission and distribution storm hardening costs for incremental activities that are not already included in base rates. The FPSC is directed to implement the law and propose a rule for adoption no later than October 31, 2019.

In July 2019, the FPSC approved a petition filed by PGS for authority to record AFUDC at an annual rate of 5.97% as part of its plans to develop three expansion projects in 2019 and 2020.

The table below sets forth the June 30, 2019 liquidity, cash balances and amounts available under the TEC credit facilities.

TEC expects to fund capital expenditures and reduce short-term borrowings in the third quarter of 2019 with cash proceeds from the sale of its $300 million aggregate principal amount of unsecured notes on July 24, 2019, cash from operating activities and available cash on hand. See Note 7 to the TEC Consolidated Condensed Financial Statements and Capital Investments below for further information.

Cash flows from operating activities for the six months ended June 30, 2019 were $331 million, a decrease of $15 million compared to the same period in 2018. The decrease is primarily due to the timing of accounts payable and prepayments and lower base rates due to the impact of tax reform, partially offset by increases in revenue collected for the in-service of solar generation projects and lower fuel under-recoveries.

Cash flows from financing activities for the six months ended June 30, 2019 resulted in net cash inflows of $245 million. TEC received $220 million of equity contributions from Parent and $165 million of net proceeds from borrowings under credit agreements (see Note 6 to the TEC Consolidated Condensed Financial Statements for further information regarding TEC’s credit agreements). These increases in cash flows were partially offset by dividend payments to Parent of $140 million.

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2019, 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, 2019. Reference is made to the specific agreements and instruments for more details.

Certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 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, 2019.

In 2019, TEC expects to invest approximately $1,255 million in capital projects, excluding AFUDC-debt and equity. This represents an increase of approximately $45 million from the 2019 forecasted capital investments amount disclosed in TEC’s Annual Report on Form 10-K for the year ended December 31, 2018. The increase is primarily due to timing of solar construction.

Tampa Electric expects to spend approximately $850 million during 2017 through 2021 related to the 600 MW solar project recoverable under the SoBRAs as discussed in Note 3 to the TEC Consolidated Condensed Financial Statements, approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, which received final state approval on July 25, 2019, and approximately $235 million during 2018 through 2022 for an AMI project. TEC intends to fund those capital expenditures with available cash on hand, cash generated from operating activities, and cash from equity contributions and debt issuances so that Tampa Electric and PGS maintain their capital structures consistent with existing regulatory arrangements. Actual capital expenditures could vary materially due to changes in schedule, costs for materials or labor or changes in plans.

The valuation methods used to determine fair value are described in Notes 7 and 13 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, 2019, the fair value of derivatives was not materially affected by nonperformance risk.

Critical accounting policies and estimates have not materially changed in 2019. For further discussion of critical accounting policies and estimates, see TEC’s Annual Report on Form 10-K for the year ended December 31, 2018.

On June 19, 2019, EPA released the final rule to replace the Clean Power Plan (CPP), named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing fossil fuel-fired electric generating units (EGUs). The rule provides emission guidelines to replace the CPP and inform the development of state plans to reduce GHG emissions from certain coal-fired EGUs. In the guidelines, EPA determined that heat rate improvement measures are the best system of emission reduction for existing coal-fired EGUs. This action also provides implementing regulations for emission guidelines issued under Section 111(d) of the Clean Air Act. Tampa Electric has emission units that are subject to this rule and is preparing to engage in the development of a state plan that could be finalized by 2020.

The outcome of expected litigation and the rule-making process and its impact on TEC’s businesses is uncertain at this time; however, it could result in increased operating costs, and/or decreased operations at Tampa Electric’s coal-fired plants. Depending on

how the state plan could be developed and implemented, the ACE rule could cause an increase in costs or rates charged to customers, which could curtail sales.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding.

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

From time to time, TEC is involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. For a discussion of legal proceedings and environmental matters, see Note 8 of the TEC Consolidated Condensed Financial Statements.

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


Title of each class	Trading symbol(s)	Name of each exchange on which registered
None.

Term		Meaning
OPC		Office of Public Counsel
OPEB		other postemployment benefits
Parent		TECO Energy, Inc., the direct parent company of Tampa Electric Company
PBGC		Pension Benefit Guarantee Corporation
PBO		projected benefit obligation
PGA		purchased gas adjustment
PGS		Peoples Gas System, the gas division of Tampa Electric Company
PPA		power purchase agreement
PRP		potentially responsible party
R&D		research and development
REIT		real estate investment trust
RFP		request for proposal
Regulatory ROE		return on common equity as determined for regulatory purposes
ROE		return on common equity
ROU		right-of-use
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


Level 1:	Observable inputs, such as quoted prices in active markets;
Level 2:	Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and
Level 3:	Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.


(millions)
Credit facilities	$	475
Drawn amounts/letters of credit		387
Available credit facilities		88
Cash and short-term investments		10
Total liquidity	$	98

			Calculation at
Instrument ⁽¹⁾	Financial Covenant ⁽²⁾	Requirement/Restriction	June 30, 2019
Credit facility - $325 million	Debt/capital	Cannot exceed 65%	45.4%
Accounts receivable credit facility - $150 million	Debt/capital	Cannot exceed 65%	45.4%

(millions)	Classification	June 30, 2019
Right-of-use asset	Other deferred debits	$	17
Lease liabilities
Current	Other current liabilities	$	1
Long-term	Deferred credits and other liabilities		17
Total lease liabilities		$	18

Six months ended June 30,	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	2
Weighted average remaining lease term (years)		48
Weighted average discount rate - operating leases		4.3	%

(millions)	June 30, 2019
Total minimum lease payments to be received	$	35
Less amounts representing estimated executory costs		(13	)
Minimum lease payments receivable	$	22
Less unearned finance lease income		(11	)
Net investment in direct finance leases	$	11
Principal due within one year (included in "Receivables")		(1	)
Net investment in direct finance leases - long-term (included in "Other deferred debits")	$	10

	S&P	Moody’s	Fitch ⁽¹⁾
Credit ratings of senior unsecured debt	BBB+	A3	A
Credit ratings outlook	Negative	Stable	Stable

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).	*

31.1	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ⁽¹⁾

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

	TAMPA ELECTRIC COMPANY
	(Registrant)

Date: August 12, 2019	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)