10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2019

OR

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

For the transition period from                     to                     .

Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY (Exact name of registrant as specified in its charter)
Arizona (State or other jurisdiction of incorporation or organization)	86-0062700 (I.R.S. Employer Identification No.)
88 East Broadway Boulevard, Tucson, AZ 85701 (Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000
Former name, former address and former fiscal year, if changed since last report: N/A

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 x No o

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

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

Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer x Smaller Reporting Company o Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant 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. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

All shares of outstanding common stock of Tucson Electric Power Company are held by its parent company, UNS Energy Corporation, which is an indirect, wholly-owned subsidiary of Fortis Inc. There were 32,139,434 shares of common stock, no par value, outstanding as of April 30, 2019.

i

Table of Contents

Definitions	iii
Forward-Looking Information	v
PART I
Item 1. Financial Statements
Condensed Consolidated Statements of Income	1
Condensed Consolidated Statements of Comprehensive Income	2
Condensed Consolidated Statements of Cash Flows	3
Condensed Consolidated Balance Sheets	4
Condensed Consolidated Statements of Changes in Stockholder's Equity	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Critical Accounting Policies and Estimates	32
New Accounting Standards Issued and Not Yet Adopted	32
Item 3. Quantitative and Qualitative Disclosures about Market Risk	32
Item 4. Controls and Procedures	32
PART II
Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 6. Exhibits	35
Signatures	36

ii

DEFINITIONS

The abbreviations and acronyms used in this Form 10-Q are defined below:

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

2019 Rate Case	A pending general rate case filed with the ACC by TEP in April 2019 requesting new rates be implemented in May 2020
ACC	Arizona Corporation Commission
ACC Refund Order	An order issued by the ACC approving TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability that reflects the deferral of the return of a portion of the savings, effective May 1, 2018
AFUDC	Allowance for Funds Used During Construction
AMT	Alternative Minimum Tax
DG	Distributed Generation
DSM	Demand Side Management
EDIT	Excess Deferred Income Taxes
EE Standards	Energy Efficiency Standards
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles in the United States of America
Gila Acquisition	SRP entered into an agreement to acquire Gila River Units 1 and 2 from third-parties
LFCR	Lost Fixed Cost Recovery
LOC	Letter(s) of Credit
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
RES	Renewable Energy Standard
Retail Rates	Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
RICE	Reciprocating Internal Combustion Engine
TCA	Transmission Cost Adjustor
TCJA	Tax Cuts and Jobs Act
TEAM	Tax Expense Adjustor Mechanism
Tolling PPA	A 20-year tolling PPA that TEP entered into in 2017 with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which includes a three-year option to purchase the unit
VIE	Variable Interest Entity

ENTITIES AND GENERATING STATIONS

Fortis	Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners	Four Corners Generating Station
Gila River	Gila River Generating Station
Luna	Luna Generating Station
Navajo	Navajo Generating Station
San Juan	San Juan Generating Station
SES	Southwest Energy Solutions, Inc.
Springerville	Springerville Generating Station

iii

SRP	Salt River Project Agricultural Improvement and Power District
Sundt	H. Wilson Sundt Generating Station
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Tri-State	Tri-State Generation and Transmission Association, Inc.
UNS Electric	UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy	UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates	Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas	UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation

UNITS OF MEASURE

BBtu	Billion British thermal unit(s)
GWh	Gigawatt-hour(s)
kWh	Kilowatt-hour(s)
MW	Megawatt(s)
MWh	Megawatt-hour(s)

iv

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. TEP, or the Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as may otherwise be required by the federal securities laws.

Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed therein. We express our estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part I, Item 1A. Risk Factors of our 2018 Form 10-K; Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax and energy policies; changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output or accelerate generation facility retirements; the outcome of the general rate case filed with the ACC in April 2019; regional economic and market conditions that could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; our forecasts of peak demand and whether existing generation capacity and PPA are sufficient to meet the expected demand and reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and the related contribution requirements and expenses; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and DG initiatives; changes to long-term contracts; the cost of fuel and power supplies; the ability to obtain coal from our suppliers; cyber-attacks, data breaches, or other challenges to our information security, including our operations and technology systems; the performance of TEP's generation facilities; and the impact of the TCJA on our financial condition and results of operations, including the assumptions we make relating thereto.

v

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
	2019			2018
Operating Revenues	$	333,003		$	275,091
Operating Expenses
Fuel	89,418			68,022
Purchased Power	32,850			20,364
Transmission and Other PPFAC Recoverable Costs	11,925			9,791
Increase (Decrease) to Reflect PPFAC Recovery Treatment	6,205			(7,966		)
Total Fuel and Purchased Power	140,398			90,211
Operations and Maintenance	86,588			83,156
Depreciation	41,317			38,877
Amortization	7,617			6,022
Taxes Other Than Income Taxes	14,201			14,180
Total Operating Expenses	290,121			232,446
Operating Income	42,882			42,645
Other Income (Expense)
Interest Expense	(22,131		)	(16,485		)
Allowance For Borrowed Funds	1,274			688
Allowance For Equity Funds	3,323			1,645
Other, Net	3,288			(425		)
Total Other Income (Expense)	(14,246		)	(14,577		)
Income Before Income Tax Expense	28,636			28,068
Income Tax Expense	2,441			4,265
Net Income	$	26,195		$	23,803

The accompanying notes are an integral part of these financial statements.

1

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
	2019		2018
Comprehensive Income
Net Income	$	26,195	$	23,803
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $9 and $41	28		123
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $22 and $40	66		115
Total Other Comprehensive Income, Net of Tax	94		238
Total Comprehensive Income	$	26,289	$	24,041

The accompanying notes are an integral part of these financial statements.

2

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
	2019			2018
Cash Flows from Operating Activities
Net Income	$	26,195		$	23,803
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	41,317			38,877
Amortization Expense	7,617			6,022
Amortization of Debt Issuance Costs	571			589
Use of Renewable Energy Credits for Compliance	8,275			7,476
Deferred Income Taxes	4,191			5,915
Pension and Other Postretirement Benefits Expense	4,440			3,818
Pension and Other Postretirement Benefits Funding	(1,744		)	(1,498		)
Allowance for Equity Funds Used During Construction	(3,323		)	(1,645		)
Regulatory Deferral, ACC Refund Order	1,707			—
Changes in Current Assets and Current Liabilities:
Accounts Receivable	25,319			8,603
Materials, Supplies, and Fuel Inventory	(3,537		)	8,344
Regulatory Assets	(3,400		)	(4,601		)
Other Current Assets	(9,449		)	(30		)
Accounts Payable and Accrued Charges	(22,687		)	(14,938		)
Income Taxes Receivable	(1,424		)	—
Regulatory Liabilities	6,587			2,470
Other, Net	1,078			906
Net Cash Flows—Operating Activities	81,733			84,111
Cash Flows from Investing Activities
Capital Expenditures	(106,279		)	(82,805		)
Purchase Intangibles, Renewable Energy Credits	(9,704		)	(10,106		)
Contributions in Aid of Construction	2,852			5,467
Net Cash Flows—Investing Activities	(113,131		)	(87,444		)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	—			27,000
Repayments of Borrowings, Revolving Credit Facility	—			(31,000		)
Payments of Finance Lease Obligations	(10,889		)	(10,930		)
Other, Net	383			341
Net Cash Flows—Financing Activities	(10,506		)	(14,589		)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash	(41,904		)	(17,922		)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	152,747			49,501
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	110,843		$	31,579

The accompanying notes are an integral part of these financial statements.

3

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	March 31, 2019			December 31, 2018
ASSETS
Utility Plant
Plant in Service	$	6,051,817		$	6,020,469
Utility Plant Under Finance Leases	248,635			248,635
Construction Work in Progress	290,517			258,965
Total Utility Plant	6,590,969			6,528,069
Accumulated Depreciation and Amortization	(2,306,282		)	(2,293,783		)
Accumulated Amortization of Finance Lease Assets	(76,737		)	(73,646		)
Total Utility Plant, Net	4,207,950			4,160,640
Investments and Other Property	54,598			50,952
Current Assets
Cash and Cash Equivalents	96,441			138,114
Accounts Receivable, Net	142,339			172,367
Fuel Inventory	24,688			22,783
Materials and Supplies	109,622			107,990
Regulatory Assets	117,237			106,725
Derivative Instruments	3,027			3,929
Other	36,772			25,571
Total Current Assets	530,126			577,479
Regulatory and Other Assets
Regulatory Assets	289,566			293,078
Derivative Instruments	12,663			8,402
Other	77,886			68,656
Total Regulatory and Other Assets	380,115			370,136
Total Assets	$	5,172,789		$	5,159,207

The accompanying notes are an integral part of these financial statements.

(Continued)

4

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	March 31, 2019			December 31, 2018
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2019 and December 31, 2018)	$	1,346,539		$	1,346,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	510,472			484,277
Accumulated Other Comprehensive Loss	(4,620		)	(4,714		)
Total Common Stock Equity	1,846,034			1,819,745
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2019 and December 31, 2018)	—			—
Finance Lease Obligations	6,192			19,773
Long-Term Debt, Net	1,615,869			1,615,252
Total Capitalization	3,468,095			3,454,770
Current Liabilities
Finance Lease Obligations	175,202			172,510
Accounts Payable	103,076			133,012
Accrued Taxes Other than Income Taxes	53,872			41,686
Accrued Employee Expenses	20,143			34,339
Accrued Interest	18,337			17,927
Regulatory Liabilities	101,219			95,094
Customer Deposits	26,136			27,650
Derivative Instruments	26,367			18,137
Other	23,171			21,555
Total Current Liabilities	547,523			561,910
Regulatory and Other Liabilities
Deferred Income Taxes, Net	376,394			369,705
Regulatory Liabilities	503,259			512,425
Pension and Other Postretirement Benefits	118,361			117,472
Derivative Instruments	24,571			19,361
Other	134,586			123,564
Total Regulatory and Other Liabilities	1,157,171			1,142,527
Commitments and Contingencies
Total Capitalization and Other Liabilities	$	5,172,789		$	5,159,207

The accompanying notes are an integral part of these financial statements.

(Concluded)

5

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in thousands)

	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances as of December 31, 2017	$	1,296,539	$	(6,357	)	$	380,076	$	(6,226	)	$	1,664,032
Net Income						23,803					23,803
Other Comprehensive Income, Net of Tax								238			238
Adoption of ASU, Cumulative Effect Adjustment						878		(878		)	—
Balances as of March 31, 2018	$	1,296,539	$	(6,357	)	$	404,757	$	(6,866	)	$	1,688,073

	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances as of December 31, 2018	$	1,346,539	$	(6,357	)	$	484,277	$	(4,714	)	$	1,819,745
Net Income						26,195					26,195
Other Comprehensive Income, Net of Tax								94			94
Balances as of March 31, 2019	$	1,346,539	$	(6,357	)	$	510,472	$	(4,620	)	$	1,846,034

The accompanying notes are an integral part of these financial statements.

6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 427,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2018 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

As of March 31, 2019, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Restricted Cash

Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:

	Three Months Ended March 31,
(in millions)	2019		2018
Cash and Cash Equivalents	$	96	$	20
Restricted Cash included in:
Investments and Other Property	14		10
Current Assets—Other	1		2
Total Cash, Cash Equivalents, and Restricted Cash	$	111	$	32

Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

Leases

TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance will be applied on a prospective basis to all new or modified land easements after January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 6 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 2. REGULATORY MATTERS

The ACC and the FERC each regulate portions of utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

2019 RATE CASE

On April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018. The filing requests new rates be implemented in May 2020.

The key proposals of the rate case include:

• a non-fuel retail revenue increase of $115 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76 million, or 7.8%, over test year retail revenues;

• a 7.68% return on original cost rate base of $2.7 billion;

• a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

• a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and

• a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

TEP cannot predict the outcome of the proceeding.

FEDERAL TAX LEGISLATION

Arizona Corporation Commission

In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018 (ACC Refund Order). The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. The 2018 refund amount totaled $33 million. TEP filed an information filing with the ACC to establish its 2019 customer refund of $34 million.

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	4		$	—
ACC Refund (Reduction in Operating Revenues)	(7		)	(7		)
Amount Returned to Customers through Bill Credits	4			—
Regulatory Deferral	2			—
End of Period	$	3		$	(7	)

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.

9

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.

The table below summarizes the PPFAC regulatory asset (liability) balance:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs	(3		)	2
PPFAC Refunds (Recoveries) (1)	(2		)	3
End of Period	$	(22	)	$	(4	)

⁽¹⁾  The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement is 9% of retail electric sales in 2019 and increases annually until renewable retail sales represent at least 15% by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC.

In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million, which is recovered through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million for the three months ended March 31, 2019 and 2018, related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.

In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is collected through the DSM surcharge.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues.

TEP recorded regulatory assets and recognized LFCR revenues of $10 million and $8 million in the three months ended March 31, 2019 and 2018, respectively. LFCR revenues are included in Operating Revenues on the Condensed Consolidated Statements of Income.

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below:

($ in millions)	Remaining Recovery Period (years)	March 31, 2019		December 31, 2018
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	124	$	126
Early Generation Retirement Costs (1)	Various	70		72
Income Taxes Recoverable through Future Rates (2)	Various	46		47
Lost Fixed Cost Recovery	2	40		35
Derivatives (Note 9)	11	36		27
Final Mine Reclamation and Retiree Healthcare Costs (3)	19	27		29
Property Tax Deferrals (4)	1	24		23
Springerville Unit 1 Leasehold Improvements (5)	4	11		11
Other Regulatory Assets	Various	29		30
Total Regulatory Assets		407		400
Less Current Portion	1	117		107
Total Non-Current Regulatory Assets		$	290	$	293

Regulatory Liabilities
Income Taxes Payable through Future Rates (2)	Various	$	350	$	354
Net Cost of Removal (6)	Various	165		171
Renewable Energy Standard	Various	54		52
Purchased Power and Fuel Adjustment Clause	1	22		17
Deferred Investment Tax Credits (7)	Various	7		7
Other Regulatory Liabilities	Various	6		6
Total Regulatory Liabilities		604		607
Less Current Portion	1	101		95
Total Non-Current Regulatory Liabilities		$	503	$	512

⁽¹⁾  Includes the net book value and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10-year period in the 2019 Rate Case.

⁽²⁾  Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA.

⁽³⁾  Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038.

⁽⁴⁾  Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.

⁽⁵⁾  Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.

⁽⁶⁾  Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant which are not yet expended.

⁽⁷⁾  Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

11

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates related to the EDIT balances, TEP does not pay a return on regulatory liabilities.

NOTE 3. REVENUE

DISAGGREGATION OF REVENUES

TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:

	Three Months Ended March 31,
(in millions)	2019		2018
Retail	$	202	$	192
Wholesale	84		38
Other Services	24		23
Revenues from Contracts with Customers	310		253
Alternative Revenues	12		9
Other	11		13
Total Operating Revenues	$	333	$	275

NOTE 4. ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2019			December 31, 2018
Customer (1)	$	85		$	99
Customer, Unbilled	35			45
Due from Affiliates (Note 5)	9			8
Other	18			25
Allowance for Doubtful Accounts	(5		)	(5		)
Accounts Receivable, Net	$	142		$	172

⁽¹⁾  Includes $6 million as of March 31, 2019, and $8 million as of December 31, 2018, of receivables related to revenue from derivative instruments.

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 5. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and the UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor related services.

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2019		December 31, 2018
Receivables from Related Parties
UNS Electric	$	5	$	7
UNS Gas	1		1
UNS Energy	3		—
Total Due from Related Parties	$	9	$	8
Payables to Related Parties
SES	$	2	$	2
UNS Energy	1		1
UNS Electric	—		1
UNS Gas	1		1
Total Due to Related Parties	$	4	$	5

The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:

	Three Months Ended March 31,
(in millions)	2019		2018
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	1	$	2
Control Area Services, UNS Electric (2)	1		—
Common Costs, UNS Energy Affiliates (3)	5		4
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (4)	3		3
Corporate Services, UNS Energy (5)	1		2
Corporate Services, UNS Energy Affiliates (6)	1		2
Capacity Charges, UNS Gas	1		—

⁽¹⁾  TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.

⁽²⁾  TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.

⁽³⁾  Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

⁽⁴⁾  SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁵⁾  Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $2 million for the three months ended March 31, 2019 and 2018.

⁽⁶⁾  Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 6. LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.

TEP leases generating facilities, land, rail cars, and communication tower space with remaining terms of one to 23 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s finance leases are included in Utility Plant Under Finance Leases, Accumulated Amortization of Finance Lease Assets, and current and non-current Finance Lease Obligations on the Condensed Consolidated Balance Sheets. TEP expects to exercise its option to purchase Gila River Unit 2 in December 2019. The purchase price is included in Current Liabilities—Finance Lease Obligations. Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options.

TEP’s operating leases are included on the balance sheet as follows:

(in millions)	March 31, 2019
Regulatory and Other Assets, Other	$	8
Current Liabilities, Other	1
Regulatory and Other Liabilities, Other	7

The following table presents the components of TEP’s lease cost:

	Three Months Ended
(in millions)	March 31, 2019
Finance
Amortization of Leased Assets	$	3
Interest on Lease Liabilities (1)	3
Variable	4
Total Lease Cost	$	10

⁽¹⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.

Operating lease cost for the three months ended March 31, 2019, was not material to TEP's financial position or results of operations.

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

As of March 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable real estate taxes and common area maintenance:

(in millions)	Operating Leases		Finance Leases (1)		Total
2019	$	1	$	173	$	174
2020	1		20		21
2021	1		—		1
2022	1		—		1
2023	1		—		1
Thereafter	5		—		5
Total Lease Payments	10		193		203
Less Imputed Interest	2		12		14
Total Lease Obligations	8		181		189
Less Current Portion	1		175		176
Total Non-Current Lease Obligations	$	7	$	6	$	13

⁽¹⁾  Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

The following table presents TEP's lease terms and discount rate related to its leases:

	March 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	7.1	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Three Months Ended
(in millions)	March 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	(4	)
Financing Cash Flows used for Finance Leases	(11		)
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities
Operating Leases	8

Operating cash flows from operating leases for the three months ended March 31, 2019, were not material.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to eight years. Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years.

Operating lease income for the three months ended March 31, 2019, was not material to TEP's results of operations. TEP's expected operating lease payments to be received at March 31, 2019, are $1 million in each of 2019 through 2023 and $1 million thereafter.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Operating Leases		Capital Leases
2019	$	1	$	187
2020	1		20
2021	1		—
2022	1		—
2023	1		—
Thereafter	5		—
Total Lease Payments	$	10	207
Less: Imputed Interest			14
Total Lease Obligations			193
Less: Current Portion			173
Total Non-Current Lease Obligations			$	20

Operating lease cost for the three months ended March 31,2018, was not material to TEP's results of operations.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

In addition to those reported in its 2018 Annual Report on Form 10-K, TEP entered into the following long-term commitment:

In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million. TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence in 2019 and be completed by December 2020.

CONTINGENCIES

Legal Matters

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP and are disclosed below.

Claims Related to San Juan Generating Station

WildEarth Guardians

In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to San Juan Coal Company (SJCC)) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, including: (i) failure to provide requisite public notice and participation, and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSMRE so the OSMRE may prepare a new Environmental Impact Statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSMRE's decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. In May 2018, the OSMRE released a draft EIS

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

for public comment which was open through July 2018. On March 15, 2019, the OSMRE published a Notice of Availability in the Federal Register to announce the publication of the final EIS. The OSMRE issued a final record of decision on April 30, 2019. The final decision contemplates continued operation of the San Juan Mine. Public Service Company of New Mexico, operator of San Juan, is evaluating the final decision for any cost impacts that may be passed onto the participants of San Juan. TEP cannot currently predict the potential impact of these costs.

Mine Reclamation at Generation Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s estimated share of mine reclamation costs at all three mines is $65 million. Payments will be made through the expiration of the coal supply agreements, which expire between December 2019 and 2031. An aggregate liability balance related to final mine reclamation of $37 million as of March 31, 2019, and $36 million as of December 31, 2018 was reflected in current and non-current Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid out.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of March 31, 2019, there have been no such payment defaults under any of the participation agreements. The participation agreements expire in: (i) December 2019 at Navajo; (ii) 2022 at San Juan; (iii) 2041 at Four Corners; and (iv) 2046 at Luna.

Environmental Matters

TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance, in all material respects, with applicable environmental laws and regulations.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,
(in millions)	2019			2018			2019		2018
Service Cost	$	3		$	4		$	1	$	1
Non-Service Cost (1)
Interest Cost	4			4			—		—
Expected Return on Plan Assets	(6		)	(7		)	—		—
Amortization of Net Loss	2			2			—		—
Net Periodic Benefit Cost	$	3		$	3		$	1	$	1

⁽¹⁾  The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

NOTE 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:

	Level 1		Level 2			Level 3			Total
(in millions)	March 31, 2019
Assets
Cash Equivalents (1)	$	85	$	—		$	—		$	85
Restricted Cash (1)	14		—			—			14
Energy Derivative Contracts, Regulatory Recovery (2)	—		12			3			15
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			1			1
Total Assets	99		12			4			115
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(41		)	(10		)	(51		)
Total Liabilities	—		(41		)	(10		)	(51		)
Total Assets (Liabilities), Net	$	99	$	(29	)	$	(6	)	$	64

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

(in millions)	December 31, 2018
Assets
Cash Equivalents (1)	$	125	$	—		$	—		$	125
Restricted Cash (1)	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery (2)	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			2			2
Total Assets	140		10			2			152
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	140	$	(25	)	$	—		$	115

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.

⁽²⁾  Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	March 31, 2019
Derivative Assets
Energy Derivative Contracts	$	16		$	15		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(51		)	(15		)	—		(36		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

DERIVATIVE INSTRUMENTS

TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.

The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.

For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.

TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.

Cash Flow Hedges

To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense are not material to TEP's financial position or results of operations.

As of March 31, 2019, the total notional amount of the interest rate swap was $6 million.

Energy Derivative Contracts, Regulatory Recovery

TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:

	Three Months Ended March 31,
(in millions)	2019			2018
Unrealized Net Loss	$	(9	)	$	(18	)

Energy Derivative Contracts, No Regulatory Recovery

TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism.

Derivative Volumes

As of March 31, 2019, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

	March 31, 2019	December 31, 2018
Power Contracts GWh	2,933	1,743
Gas Contracts BBtu	144,825	146,933

Level 3 Fair Value Measurements

The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:

	Valuation Approach	Fair Value of					Unobservable Inputs	Range of Unobservable Inputs
		Assets		Liabilities
(in millions)	March 31, 2019
Forward Power Contracts	Market approach	$	4	$	(10	)	Market price per MWh	$	20.50	$	89.00

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(8		)	—
Settlements	1			(1		)
End of Period	$	(6	)	$	1
Gains (Losses), Assets (Liabilities) Still Held	$	(7	)	$	—

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.

TEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.

TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.

The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $85 million as of March 31, 2019, compared with $41 million as of December 31, 2018. As of March 31, 2019, TEP had $10 million of cash posted as collateral to a counterparty to provide credit enhancement which was reflected in Current Assets—Other on the Condensed Consolidated Balance Sheet. As of April 30, 2019, there was no collateral posted as it was no longer required by the counterparty and the entire amount was returned to TEP. If the credit risk contingent features were triggered on March 31, 2019, TEP would have been required to post an additional $75 million of collateral of which $13 million relates to outstanding net payable balances for settled positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt:

	Fair Value Hierarchy	Face Value				Fair Value
(in millions)		March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,629	$	1,629	$	1,703	$	1,672

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis explains the results of operations, the financial condition, and the outlook for TEP. It includes the following:

• outlook and strategies;

• results of operations in the first three months of 2019 compared with the same period in 2018;

• factors affecting results of operations;

• liquidity and capital resources including: (i) capital expenditures; (ii) contractual obligations; and (iii) environmental matters;

• critical accounting policies and estimates; and

• new accounting standards issued and not yet adopted.

Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP financial measures.

Management’s Discussion and Analysis should be read in conjunction with the financial statements and accompanying notes that appear in Part I, Item 1 of this Form 10-Q. For information on factors that may cause our future results to differ from those we currently expect or anticipate, see Forward-Looking Information at the front of this Form 10-Q and Risk Factors in Part 1, Item 1A of our 2018 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.

References in this discussion and analysis to "we" and "our" are to TEP.

OUTLOOK AND STRATEGIES

TEP's financial prospects and outlook are affected by many factors including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory and legislative actions. Our plans and strategies include the following:

• Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe and reliable service.

• Continuing to focus on our long-term resource diversification strategy, including transitioning from carbon intensive sources to a more sustainable energy portfolio, while providing rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. This long-term strategy includes a target of meeting 30% of our customers’ energy needs with non-carbon emitting resources by 2030. This resource strategy may be impacted by various energy policy proposals currently under consideration in Arizona.

• Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.

2019 Operational and Financial Highlights

Management's Discussion and Analysis includes the following notable items:

• Entered into an agreement to develop a 247 MW wind-power electric generation facility which is expected to be completed by December 2020.

• Filed a general rate case with the ACC based on a test year ended December 31, 2018, that includes a non-fuel retail revenue increase of $115 million.

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RESULTS OF OPERATIONS

Because weather and other factors cause seasonal fluctuations in sales of power, our quarterly results of operation are not indicative of annual results. TEP's summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first quarter of the year, due to mild winter weather in our retail service territory.

The following discussion provides the significant items that affected TEP's results of operations in the first three months of 2019 compared with the same period in 2018. The significant items affecting net income are presented on an after-tax basis.

The first three months of2019 compared with the first three monthsof2018

TEP reported net income of $26 million in the first three months of 2019 compared with net income of $24 million in the first three months of 2018. The increase of $2 million, or 8%, was primarily due to:

• $3 million in higher retail revenue primarily due to an increase in usage related to favorable weather;

• $3 million increase in the value of company-owned life insurance as a result of favorable market conditions;

• $2 million in lower income tax expense due to the recognition of additional AMT credits related to a revision in tax law guidance; and

• $2 million in higher AFUDC related to an increase in construction projects.

The increase was partially offset by:

• $3 million in higher operations and maintenance expense resulting primarily from an increase in expense related to planned outages in 2019;

• $3 million in higher depreciation and amortization expense due to an increase in asset base; and

• $2 million in higher interest expense related to a debt issuance in November 2018.

Retail Revenues and Key Statistics

The following table provides key statistics impacting operating revenues:

	Three Months Ended March 31,				Increase (Decrease)
($ and kWh in millions)	2019		2018		Percent
Operating Revenues	$	333	$	275	21.1	%
Electric Sales (kWh)
Residential	705		648		8.8	%
Commercial	436		427		2.1	%
Industrial	427		440		(3.0	)%
Mining	264		252		4.8	%
Public Authorities	4		4		—	%
Total Retail Sales	1,836		1,771		3.7	%
Wholesale, Long-Term	135		79		70.9	%
Wholesale, Short-Term	2,047		1,099		86.3	%
Total Electric Sales	4,018		2,949		36.2	%
Average Revenue Per kWh (Cents/kWh)
Retail	11.02		10.85		1.6	%
Wholesale	3.77		3.71		1.6	%
Total Retail Customers	426,756		424,116		0.6	%

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Operating Revenues increased by $58 million in the first three months of 2019 when compared with the same period in 2018 primarily due to: (i) an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2; (ii) an increase in fuel and purchase power recoveries as a result of higher PPFAC rates; and (iii) higher retail sales as a result of favorable weather.

Short-term wholesale revenues are primarily related to ACC jurisdictional assets and are returned to retail customers by offsetting fuel and purchased power costs eligible for recovery through the PPFAC. Revenues related to Springerville Units 3 and 4 are primarily reimbursements by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with the corresponding expense recorded in Operating Expenses on the Condensed Consolidated Statements of Income.

Operating Expenses

Fuel and Purchased Power Expense

Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, increased by $50 million, or 56%, in the first three months of 2019 when compared with the same period in 2018. The increase was primarily due to an increase in: (i) generation output; (ii) Purchased Power, Non-Renewable price and volumes; and (iii) recovery of PPFAC costs as a result of changes in the PPFAC rate. The increases were partially offset by a decrease in the average cost of coal.

The following table presents TEP’s sources of energy and average cost of power by type:

	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2019	2018	Percent
Sources of Energy
Coal-Fired Generation	1,766	1,714	3.0	%
Gas-Fired Generation	1,832	882	107.7	%
Utility-Owned Renewable Generation	20	18	11.1	%
Total Generation	3,618	2,614	38.4	%
Purchased Power, Non-Renewable	420	311	35.0	%
Purchased Power, Renewable	144	155	(7.1	)%
Total Generation and Purchased Power	4,182	3,080	35.8	%

(cents per kWh)
Average Fuel Cost of Generated Power
Coal	2.16	2.73	(20.9	)%
Natural Gas	2.75	2.27	21.1	%
Average Cost of Purchased Power
Purchased Power, Non-Renewable	4.08	2.91	40.2	%
Purchased Power, Renewable	9.25	9.28	(0.3	)%

Operations and Maintenance Expense

Operations and Maintenance Expense increased by $3 million, or 4%, in the first three months of 2019 when compared with the same period in 2018. The increase was primarily due to an increase in maintenance expense related to planned generation outages in 2019.

Expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income. Expenses related to customer funded renewable energy and DSM programs are collected from customers with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income.

Depreciation and Amortization Expense

Depreciation and Amortization Expense increased by $4 million, or 9%, in the first three months of 2019 when compared with the same period in 2018 primarily due to an increase in asset base.

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Other Income (Expense)

Other Income (Expense) decreased by less than $1 million, or 2%, in the first three months of 2019 when compared with the same period in 2018 primarily due to: (i) an increase in the value of company-owned life insurance as a result of favorable market conditions; and (ii) an increase in AFUDC related to an increase in construction projects. The decrease was partially offset by an increase in interest expense related to: (i) a debt issuance in November 2018; and (ii) Gila River Unit 2 demand charges, which are recovered through the PPFAC, and accounted for as finance lease interest expense.

Income Tax Expense

Income Tax Expense decreased by $2 million, or 43%, in the first three months of 2019 when compared with the same period in 2018. The decrease was primarily due to the recognition of AMT credits related to a revision in tax law guidance.

FACTORS AFFECTING RESULTS OF OPERATIONS

Regulatory Matters

TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2018 Annual Report on Form 10-K and new regulatory matters occurring in 2019.

2019 Rate Case

On April 1, 2019, TEP filed a general rate case with the ACC to provide TEP with an opportunity to recover its full cost of service, including an appropriate return on its rate base investments and enable TEP to continue to provide safe and reliable service. The rate application is based on a test year ended December 31, 2018. We requested new rates be implemented in May 2020.

The key provisions of the rate case include:

• a non-fuel retail revenue increase of $115 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76 million, or 7.8%, over test year retail revenues;

• a 7.68% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.35% and an average cost of debt of 4.65%;

• a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;

• a request to recover costs of changes in generation resource, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

• a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and

• a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

TEP cannot predict the outcome of this proceeding.

Federal Income Tax Legislation

Arizona Corporation Commission

In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved the ACC Refund Order effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales. Any over or under collected amounts are deferred to a regulatory asset or liability and will be used to adjust the following year's bill credit amounts.

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Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP filed an application with the ACC to establish the 2019 customer refund of $34 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019. TEP is allowed to defer 25% of the 2019 refund into a regulatory liability and 50% of any additional refunds in future years. As part of the 2019 Rate Case, we requested a TEAM that is intended to allow for the timely pass through to our customers of any income tax effects that materially impact revenue requirements as a result of federal or state income tax legislation. TEP has proposed the refunds deferred in the regulatory liability account be returned to customers through the TEAM in the same year the 2019 Rate Case is completed.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 and Liquidity and Capital Resources, Income Tax Position of this Form 10-Q for additional information regarding the ACC Refund Order.

Generation Resources

TEP’s long-term strategy is to transition to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. Recent changes in market conditions, including lower natural gas prices and a decrease in the cost of renewables, has aided this transition. These factors, in combination with increasingly stringent environmental requirements, has shifted the preference of coal as a primary fuel source to a more balanced energy portfolio of coal, natural gas, and renewable resources. Going forward, the rate and direction of change of these markets and regulatory regulation is uncertain, and the pace of our energy transition will need to adjust accordingly. These adjustments may include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.

As of March 31, 2019, approximately 40% of our generation capacity, including owned and leased resources, was from coal-fired generation.

See Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding the impact of environmental matters on generation facility operations.

Arizona Energy Policy

In August 2018, the ACC opened a rulemaking docket to evaluate several energy policies. The docket will review possible modifications to existing renewable energy, energy efficiency requirements, and retail competition for generation services. The adoption of new policies would be subject to rulemaking proceedings at the ACC. We would seek the ACC's approval to recover any costs related to new energy policies or requirements. TEP cannot predict the outcome of this matter or the impact on the Company's financial position or results of operations.

Navajo Generating Station

In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through 2019 and begin decommissioning activities thereafter. Navajo is expected to shut down on or before December 22, 2019. We are currently recovering Navajo's capital and operating costs in base rates using a useful life through 2030. Due to the early retirement of Navajo, we have requested recovery of final retirement costs over a 10-year period, in the 2019 Rate Case. As of March 31, 2019, the net book value of Navajo was $42 million, and we have estimated other related costs to be $4 million.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Navajo.

Sundt Generating Station

In 2017, TEP submitted an Air Quality Permit Application to the Pima County Department of Environmental Quality related to a generation modernization project at Sundt. Under the project, TEP will place in service 10 natural gas RICE units with a total nominal generation capacity of 190 MW. The final permit was issued in December 2018. Construction is underway with the RICE units scheduled for commercial operation by the end of the first quarter of 2020. We have requested recovery of the RICE project costs in the 2019 Rate Case.

The RICE units will balance the variability of intermittent renewable energy resources and will replace 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which are less efficient and lack the quick start, fast ramp capabilities of the RICE units. TEP will discontinue operation of Sundt Units 1 and 2 prior to start-up of the first RICE unit. We are currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. Due to the early retirement of Sundt Units 1 and 2, we have requested recovery of final retirement costs over a 10-year period

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in the 2019 Rate Case. As of March 31, 2019, the net book value of Sundt Units 1 and 2 was $28 million, and we have estimated other related costs to be $1 million.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Sundt Units 1 and 2.

Gila River Generating Station

In 2017, TEP entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which includes a three-year option to purchase Gila River Unit 2 (Tolling PPA). TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $164 million. We have requested recovery of the Gila River Unit 2 purchase in the 2019 Rate Case. TEP will continue to pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2 until the purchase is complete. TEP recovers the monthly demand charge through the PPFAC mechanism.

The additional 550 MW of capacity, power, and ancillary services from the Tolling PPA will allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduled for early retirement. TEP sells the capacity from the Tolling PPA into the wholesale market on a short-term basis with the associated revenues credited to the PPFAC.

Renewable Generating Facility

In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million. TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence in 2019 and be completed by December 2020. The wind project is expected to qualify for the IRS renewable Production Tax Credit. The credit is expected to recover a minimum of $250 million of the project's costs in the first 10 years, the duration of the credit after the date the facility is placed in service.

Interest Rates

See Part II, Item 7A in our 2018 Annual Report on Form 10-K and Part II, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Cash flows may vary during the year with cash flows from operations being typically the lowest in the first quarter of the year and highest in the third quarter due to TEP's summer peaking load. We use our revolving credit facility as needed to assist in funding our business activities. We believe that we have sufficient liquidity under our revolving credit facility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depends on a variety of factors, including our credit ratings and conditions in the overall capital markets.

Available Liquidity

(in millions)	March 31, 2019
Cash and Cash Equivalents	$	96
Amount Available under Revolving Credit Facility (1)	250
Total Liquidity	$	346

⁽¹⁾  TEP's revolving credit facility provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million and a maturity date of October 2022.

Future Liquidity Requirements

We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to: (i) dividend payments; (ii) debt maturities; and (iii) obligations included in the Contractual Obligations and forecasted Capital Expenditures tables reported in our 2018 Annual Report on Form 10-K and the material changes summarized below in the respective sections.

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Summary of Cash Flows

The table below presents net cash provided by (used for) operating, investing and financing activities:

	Three Months Ended March 31,						Increase (Decrease)
(in millions)	2019			2018			Percent
Operating Activities	$	82		$	84		(2.4	)%
Investing Activities	(113		)	(87		)	29.9	%
Financing Activities	(11		)	(15		)	(26.7	)%
Net Decrease	(42		)	(18		)	133.3	%
Beginning of Period	153			50			206.0	%
End of Period	$	111		$	32		246.9	%

Operating Activities

In the first three months of 2019, net cash flows from operating activities decreased by $2 million compared with the same period in 2018. The decrease is primarily due to: (i) $10 million of collateral posted to a counterparty for a credit enhancement; and (ii) $4 million in bill credits to customers related to the ACC Refund Order. The decrease was partially offset by: (i) higher retail sales as a result of favorable weather; (ii) an increase in fuel and purchase power recoveries as a result of higher PPFAC rates; and (iii) changes in working capital related to the timing of collections and payments.

Investing Activities

In the first three months of 2019, net cash flows used for investing activities increased by $26 million compared with the same period in 2018 primarily due to an increase in cash paid for capital expenditures in 2019.

Financing Activities

In the first three months of 2019, net cash flows used for financing activities decreased by $4 million compared with the same period in 2018 primarily due to a decrease in repayments, net of proceeds borrowed, under our revolving credit facility in 2018.

Sources of Liquidity

Short-Term Investments

Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of March 31, 2019, TEP's short-term investments included highly-rated and liquid money market funds and insured cash sweep accounts.

Access to Revolving Credit Facility

We have access to working capital through a revolving credit agreement with lenders. TEP expects that amounts borrowed under the credit facility will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of March 31, 2019, there was $250 million available under the revolving credit commitments and the LOC facility.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2018 Annual Report on Form 10-K for additional information regarding TEP's credit facility.

Debt Financing

We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.

In 2016, the ACC issued an order granting TEP financing authority. The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority.

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TEP anticipates raising additional capital in the second half of 2019 to: (i) finance the purchase of Gila River Unit 2; (ii) make payments for the development of a wind-powered electric generation facility; and (iii) repay borrowings under our revolving credit facility, with any remaining balance to be applied to general corporate purposes. TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, we may refinance other debt issuances or make additional debt repurchases in the future.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of March 31, 2019, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- and A3, respectively.

Our credit ratings are dependent on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.

Certain of TEP's debt agreements contain pricing based on our credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.

Debt Covenants

Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of March 31, 2019, TEP was in compliance with these covenants.

We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.

Contribution from Parent

TEP received no equity contributions in the first three months of 2019 or 2018.

Dividends Paid to Parent

TEP did not declare or pay dividends to UNS Energy in the first three months of 2019 or 2018.

Master Trading Agreements

TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, changes in TEP’s credit ratings, or material changes in TEP’s creditworthiness. As of March 31, 2019, TEP had $10 million in cash posted as collateral to a counterparty to provide credit enhancements. As of April 30, 2019, there was no collateral posted as it was no longer required by the counterparty and the entire amount was returned to TEP.

Capital Expenditures

TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In the first three months of 2019, there have been no changes in TEP's forecasted capital expenditures from those reported in our 2018 Annual Report on Form 10-K, other than normal recurring subsequent review adjustments.

Contractual Obligations

In the first three months of 2019, there have been no material changes outside the ordinary course of business to contractual obligations as reported in our 2018 Annual Report on Form 10-K, except as noted below:

• In March 2019, we entered into an agreement to develop a 247 MW wind-power electric generation facility which is expected to be completed by December 2020. We expect to make payments of $259 million in 2019 and $111 million in 2020, contingent upon certain performance obligations.

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Off-Balance Sheet Arrangements

Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2018 Annual Report on Form 10-K, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.

Income Tax Position

Tax legislation previously in effect included provisions that made qualified property placed in service before 2018 eligible for bonus depreciation for tax purposes. In addition, the Internal Revenue Service issued guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions were an acceleration of tax benefits we otherwise would have received over a longer period of time and created net operating loss carryforwards that are used to offset future taxable income.As a result, we did not pay any federal or state income taxes in the first three months of 2019. We offset net operating loss carryforwards against taxable income and do not expect to make federal or state income tax payments for the next several years.

Under the TCJA, AMT credit carryforwards will be refunded if not used to offset federal income tax liabilities. TEP received no refunds in the first three months of 2019 and expects to receive refunds of approximately $14 million in 2019, $7 million in 2020, and $3 million in 2021 and 2022.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the TCJA.

Environmental Matters

The EPA regulates the amount of sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon dioxide (CO₂), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.

Greenhouse Gas Regulation

In August 2015, the EPA issued the Clean Power Plan (CPP) limiting CO₂ emissions from existing and new fossil fuel-based generation facilities. The CPP establishes state-level CO₂ emission rates and mass-based goals that apply to fossil fuel-based generation. The plan targets CO₂ emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.

In October 2017, the EPA issued a proposal to repeal the CPP and in December 2017, the EPA issued an Advance Notice of Proposed Rulemaking soliciting information about the intent to replace the CPP with a rule establishing new emissions guidelines.

In August 2018, the EPA published the proposed Affordable Clean Energy (ACE) rule. The proposed rule is meant to replace the CPP and proposes to rebalance the roles between the states and the EPA. Under the proposed rule, the EPA would set emission guidelines based on the Best System of Emission Reduction (BSER) for Greenhouse Gas (GHG) emissions. The states would then use these emission guidelines to establish standards of performance consistent with the BSER within their jurisdictions considering source specific factors such as the remaining useful life of an individual unit. The proposed ACE rule also includes New Source Review (NSR) reform to incentivize heat-rate improvements that could reduce GHG emissions without triggering costly NSR permit requirements. Only projects that increase a generation facility’s hourly rate of pollutant emissions would be required to undergo a full NSR analysis.

Upon publication of the final rule, the states will have three years to submit plans establishing standards of performance. The EPA has 12 months to act on a complete state submittal. If a state plan is not approved, or a state fails to submit a plan within the allotted three years, the EPA would have two years to issue a federal plan. The public comment period closed October 31, 2018. The EPA anticipates finalizing the rule in 2019.

TEP will continue to work with other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed. TEP is unable to determine the impact to its facilities until all legal challenges have been resolved and any new regulations have been promulgated.

31

Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA Subtitle D) for disposal in landfills and/or surface impoundments. Due to the planned early retirement of Navajo, our share of costs to comply is less than $1 million as of March 31, 2019. We will continue to incur additional operating costs for on-going groundwater monitoring and eventual site closure. Our share of costs to comply at Four Corners is estimated to be $3 million, the majority of which is expected to be capital expenditures associated with site preparation and installation of the groundwater monitoring well system.

In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act which authorizes the States to establish permit programs under RCRA for implementing regulation for CCR. In response to the WIIN Act and RCRA rulemaking petitions, the EPA has indicated that it intends to conduct two phases of CCR rule revisions. In July 2018, the EPA signed a Phase 1, Part 1 final rule which: (i) revised groundwater protection standards for rule-specific constituents without maximum containment levels; (ii) incorporated risk-based changes under an EPA-approved state permit program or an EPA permit program; and (iii) extended certain closure deadlines. In response to challenges to this rule, the EPA filed a motion to voluntarily remand the rule but not vacate it. On March 13, 2019, the D.C. Circuit Court issued an order granting the EPA's motion, allowing the EPA nine months to undertake new rulemaking. TEP does not anticipate a material impact on operations or financial results from revisions to the Phase 1, Part 1 rule. The EPA anticipates finalizing the Phase 1, Part 2 in 2019. The second phase is also anticipated to be finalized in 2019.

TEP is currently working with other affected utilities and the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to apply accounting policies and make estimates, judgments, and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that there have been no significant changes during the three months ended March 31, 2019, to the items that we disclosed as our critical accounting policies and estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2018 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We can enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2018 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal

32

executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures are effective as of March 31, 2019.

While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during the quarter ended March 31, 2019, that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting except as noted below:

New Accounting Standards Issued and Adopted

Leases

Upon the adoption of new lease accounting guidance as of January 1, 2019, TEP implemented changes to our processes and control activities related to gathering contracts and ongoing contract review requirements. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information.

33

PART II

ITEM 1. LEGAL PROCEEDINGS

For a description of certain legal proceedings affecting TEP, refer to Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2018 Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2018 Form 10-K.

34

ITEM 6. EXHIBITS

EXHIBIT INDEX
Exhibit No.	Description
31(a)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens
31(b)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino
*32	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

35

SIGNATURES

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

		TUCSON ELECTRIC POWER COMPANY
		(Registrant)
Date:	April 30, 2019	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)

36

EX-31.A

Exhibit 31(a)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, David G. Hutchens, certify that: 

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2019, of Tucson Electric Power Company; 

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

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

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

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

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

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

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

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

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

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

Date:	April 30, 2019	/s/ David G. Hutchens
		David G. Hutchens
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Frank P. Marino, certify that: 

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2019, of Tucson Electric Power Company; 

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

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

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

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

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

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

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

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

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

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

Date:	April 30, 2019	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32

Exhibit 32

STATEMENTS OF CORPORATE OFFICERS

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Each of the undersigned, David G. Hutchens, President and Chief Executive Officer of Tucson Electric Power Company (the “Company”), and Frank P. Marino, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	April 30, 2019	/s/ David G. Hutchens
		David G. Hutchens
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	April 30, 2019	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	0000100122
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		32,139,434

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Statement [Abstract]
Operating Revenues	$ 333,003	$ 275,091
Operating Expenses
Fuel	89,418	68,022
Purchased Power	32,850	20,364
Transmission and Other PPFAC Recoverable Costs	11,925	9,791
Increase (Decrease) to Reflect PPFAC Recovery Treatment	6,205	(7,966)
Total Fuel and Purchased Power	140,398	90,211
Operations and Maintenance	86,588	83,156
Depreciation	41,317	38,877
Amortization	7,617	6,022
Taxes Other Than Income Taxes	14,201	14,180
Total Operating Expenses	290,121	232,446
Operating Income	42,882	42,645
Other Income (Expense)
Interest Expense	(22,131)	(16,485)
Allowance For Borrowed Funds	1,274	688
Allowance For Equity Funds	3,323	1,645
Other, Net	3,288	(425)
Total Other Income (Expense)	(14,246)	(14,577)
Income Before Income Tax Expense	28,636	28,068
Income Tax Expense	2,441	4,265
Net Income	$ 26,195	$ 23,803

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Net Income	$ 26,195	$ 23,803
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $9 and $41	28	123
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $22 and $40	66	115
Total Other Comprehensive Income, Net of Tax	94	238
Total Comprehensive Income	$ 26,289	$ 24,041

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Tax Expense Related to Change in Fair Value of Cash Flow Hedges	$ 9	$ 41
Tax Expense Related to Supplemental Executive Retirement Plan Adjustments	$ 22	$ 40

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Utility Plant
Plant in Service	$ 6,051,817	$ 6,020,469
Utility Plant Under Finance Leases	248,635	248,635
Construction Work in Progress	290,517	258,965
Total Utility Plant	6,590,969	6,528,069
Accumulated Depreciation and Amortization	(2,306,282)	(2,293,783)
Accumulated Amortization of Finance Lease Assets	(76,737)	(73,646)
Total Utility Plant, Net	4,207,950	4,160,640
Investments and Other Property	54,598	50,952
Current Assets
Cash and Cash Equivalents	96,441	138,114
Accounts Receivable, Net	142,339	172,367
Fuel Inventory	24,688	22,783
Materials and Supplies	109,622	107,990
Regulatory Assets	117,237	106,725
Derivative Instruments	3,027	3,929
Other	36,772	25,571
Total Current Assets	530,126	577,479
Regulatory and Other Assets
Regulatory Assets	289,566	293,078
Derivative Instruments	12,663	8,402
Other	77,886	68,656
Total Regulatory and Other Assets	380,115	370,136
Total Assets	5,172,789	5,159,207
Capitalization
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2019 and December 31, 2018)	1,346,539	1,346,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	510,472	484,277
Accumulated Other Comprehensive Loss	(4,620)	(4,714)
Total Common Stock Equity	1,846,034	1,819,745
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2019 and December 31, 2018)	0	0
Finance Lease Obligations	6,192	19,773
Long-Term Debt, Net	1,615,869	1,615,252
Total Capitalization	3,468,095	3,454,770
Current Liabilities
Finance Lease Obligations	175,202	172,510
Accounts Payable	103,076	133,012
Accrued Taxes Other than Income Taxes	53,872	41,686
Accrued Employee Expenses	20,143	34,339
Accrued Interest	18,337	17,927
Regulatory Liabilities	101,219	95,094
Customer Deposits	26,136	27,650
Derivative Instruments	26,367	18,137
Other	23,171	21,555
Total Current Liabilities	547,523	561,910
Regulatory and Other Liabilities
Deferred Income Taxes, Net	376,394	369,705
Regulatory Liabilities	503,259	512,425
Pension and Other Postretirement Benefits	118,361	117,472
Derivative Instruments	24,571	19,361
Other	134,586	123,564
Total Regulatory and Other Liabilities	1,157,171	1,142,527
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 5,172,789	$ 5,159,207

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flows from Operating Activities
Net Income	$ 26,195	$ 23,803
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	41,317	38,877
Amortization Expense	7,617	6,022
Amortization of Debt Issuance Costs	571	589
Use of Renewable Energy Credits for Compliance	8,275	7,476
Deferred Income Taxes	4,191	5,915
Pension and Other Postretirement Benefits Expense	4,440	3,818
Pension and Other Postretirement Benefits Funding	(1,744)	(1,498)
Allowance for Equity Funds Used During Construction	(3,323)	(1,645)
Regulatory Deferral, ACC Refund Order	1,707	0
Changes in Current Assets and Current Liabilities:
Accounts Receivable	25,319	8,603
Materials, Supplies, and Fuel Inventory	(3,537)	8,344
Regulatory Assets	(3,400)	(4,601)
Other Current Assets	(9,449)	(30)
Accounts Payable and Accrued Charges	(22,687)	(14,938)
Income Taxes Receivable	(1,424)	0
Regulatory Liabilities	6,587	2,470
Other, Net	1,078	906
Net Cash Flows—Operating Activities	81,733	84,111
Cash Flows from Investing Activities
Capital Expenditures	(106,279)	(82,805)
Purchase Intangibles, Renewable Energy Credits	(9,704)	(10,106)
Contributions in Aid of Construction	2,852	5,467
Net Cash Flows—Investing Activities	(113,131)	(87,444)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	0	27,000
Repayments of Borrowings, Revolving Credit Facility	0	(31,000)
Payments of Finance Lease Obligations	(10,889)	(10,930)
Other, Net	383	341
Net Cash Flows—Financing Activities	(10,506)	(14,589)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash	(41,904)	(17,922)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	152,747	49,501
Cash, Cash Equivalents, and Restricted Cash, End of Period	$ 110,843	$ 31,579

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common Stock, Shares Authorized (in shares)	75,000,000	75,000,000
Common Stock, Shares Outstanding (in shares)	32,139,434	32,139,434
Preferred Stock, Shares Authorized (in shares)	1,000,000	1,000,000
Preferred Stock, Shares Outstanding (in shares)	0	0

XML

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($) $ in Thousands	Total	Common Stock	Capital Stock Expense	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2017	$ 1,664,032	$ 1,296,539	$ (6,357)	$ 380,076	$ (6,226)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	23,803			23,803
Other Comprehensive Income, Net of Tax	238				238
Adoption of ASU, Cumulative Effect Adjustment				878	(878)
Ending balance at Mar. 31, 2018	1,688,073	1,296,539	(6,357)	404,757	(6,866)
Beginning balance at Dec. 31, 2018	1,819,745	1,346,539	(6,357)	484,277	(4,714)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	26,195			26,195
Other Comprehensive Income, Net of Tax	94				94
Ending balance at Mar. 31, 2019	$ 1,846,034	$ 1,346,539	$ (6,357)	$ 510,472	$ (4,620)

XML

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 427,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2018 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

As of March 31, 2019, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

Restricted Cash

Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:

	Three Months Ended March 31,
(in millions)	2019		2018
Cash and Cash Equivalents	$	96	$	20
Restricted Cash included in:
Investments and Other Property	14		10
Current Assets—Other	1		2
Total Cash, Cash Equivalents, and Restricted Cash	$	111	$	32

Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

Leases

TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance will be applied on a prospective basis to all new or modified land easements after January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 6 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

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REGULATORY MATTERS

3 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

The ACC and the FERC each regulate portions of utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

2019 RATE CASE

On April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018. The filing requests new rates be implemented in May 2020.

The key proposals of the rate case include:

• a non-fuel retail revenue increase of $115 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76 million, or 7.8%, over test year retail revenues;

• a 7.68% return on original cost rate base of $2.7 billion;

• a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

• a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and

• a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

TEP cannot predict the outcome of the proceeding.

FEDERAL TAX LEGISLATION

Arizona Corporation Commission

In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018 (ACC Refund Order). The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. The 2018 refund amount totaled $33 million. TEP filed an information filing with the ACC to establish its 2019 customer refund of $34 million.

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	4		$	—
ACC Refund (Reduction in Operating Revenues)	(7		)	(7		)
Amount Returned to Customers through Bill Credits	4			—
Regulatory Deferral	2			—
End of Period	$	3		$	(7	)

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.

The table below summarizes the PPFAC regulatory asset (liability) balance:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs	(3		)	2
PPFAC Refunds (Recoveries) (1)	(2		)	3
End of Period	$	(22	)	$	(4	)

⁽¹⁾  The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement is 9% of retail electric sales in 2019 and increases annually until renewable retail sales represent at least 15% by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC.

In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million, which is recovered through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million for the three months ended March 31, 2019 and 2018, related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.

In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is collected through the DSM surcharge.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues.

TEP recorded regulatory assets and recognized LFCR revenues of $10 million and $8 million in the three months ended March 31, 2019 and 2018, respectively. LFCR revenues are included in Operating Revenues on the Condensed Consolidated Statements of Income.

REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below:

($ in millions)	Remaining Recovery Period (years)	March 31, 2019		December 31, 2018
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	124	$	126
Early Generation Retirement Costs (1)	Various	70		72
Income Taxes Recoverable through Future Rates (2)	Various	46		47
Lost Fixed Cost Recovery	2	40		35
Derivatives (Note 9)	11	36		27
Final Mine Reclamation and Retiree Healthcare Costs (3)	19	27		29
Property Tax Deferrals (4)	1	24		23
Springerville Unit 1 Leasehold Improvements (5)	4	11		11
Other Regulatory Assets	Various	29		30
Total Regulatory Assets		407		400
Less Current Portion	1	117		107
Total Non-Current Regulatory Assets		$	290	$	293

Regulatory Liabilities
Income Taxes Payable through Future Rates (2)	Various	$	350	$	354
Net Cost of Removal (6)	Various	165		171
Renewable Energy Standard	Various	54		52
Purchased Power and Fuel Adjustment Clause	1	22		17
Deferred Investment Tax Credits (7)	Various	7		7
Other Regulatory Liabilities	Various	6		6
Total Regulatory Liabilities		604		607
Less Current Portion	1	101		95
Total Non-Current Regulatory Liabilities		$	503	$	512

⁽¹⁾  Includes the net book value and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10-year period in the 2019 Rate Case.

⁽²⁾  Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA.

⁽³⁾  Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038.

⁽⁴⁾  Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.

⁽⁵⁾  Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.

⁽⁶⁾  Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant which are not yet expended.

⁽⁷⁾  Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates related to the EDIT balances, TEP does not pay a return on regulatory liabilities.

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REVENUE

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

REVENUE

REVENUE

DISAGGREGATION OF REVENUES

TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:

	Three Months Ended March 31,
(in millions)	2019		2018
Retail	$	202	$	192
Wholesale	84		38
Other Services	24		23
Revenues from Contracts with Customers	310		253
Alternative Revenues	12		9
Other	11		13
Total Operating Revenues	$	333	$	275

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ACCOUNTS RECEIVABLE

3 Months Ended

Mar. 31, 2019

Receivables [Abstract]

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2019			December 31, 2018
Customer (1)	$	85		$	99
Customer, Unbilled	35			45
Due from Affiliates (Note 5)	9			8
Other	18			25
Allowance for Doubtful Accounts	(5		)	(5		)
Accounts Receivable, Net	$	142		$	172

⁽¹⁾  Includes $6 million as of March 31, 2019, and $8 million as of December 31, 2018, of receivables related to revenue from derivative instruments.

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RELATED PARTY TRANSACTIONS

3 Months Ended

Mar. 31, 2019

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and the UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor related services.

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2019		December 31, 2018
Receivables from Related Parties
UNS Electric	$	5	$	7
UNS Gas	1		1
UNS Energy	3		—
Total Due from Related Parties	$	9	$	8
Payables to Related Parties
SES	$	2	$	2
UNS Energy	1		1
UNS Electric	—		1
UNS Gas	1		1
Total Due to Related Parties	$	4	$	5

The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:

	Three Months Ended March 31,
(in millions)	2019		2018
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	1	$	2
Control Area Services, UNS Electric (2)	1		—
Common Costs, UNS Energy Affiliates (3)	5		4
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (4)	3		3
Corporate Services, UNS Energy (5)	1		2
Corporate Services, UNS Energy Affiliates (6)	1		2
Capacity Charges, UNS Gas	1		—

⁽¹⁾  TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.

⁽²⁾  TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.

⁽³⁾  Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

⁽⁴⁾  SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁵⁾  Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $2 million for the three months ended March 31, 2019 and 2018.

⁽⁶⁾  Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

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LEASES

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

LEASES

LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.

TEP leases generating facilities, land, rail cars, and communication tower space with remaining terms of one to 23 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s finance leases are included in Utility Plant Under Finance Leases, Accumulated Amortization of Finance Lease Assets, and current and non-current Finance Lease Obligations on the Condensed Consolidated Balance Sheets. TEP expects to exercise its option to purchase Gila River Unit 2 in December 2019. The purchase price is included in Current Liabilities—Finance Lease Obligations. Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options.

TEP’s operating leases are included on the balance sheet as follows:

(in millions)	March 31, 2019
Regulatory and Other Assets, Other	$	8
Current Liabilities, Other	1
Regulatory and Other Liabilities, Other	7

The following table presents the components of TEP’s lease cost:

	Three Months Ended
(in millions)	March 31, 2019
Finance
Amortization of Leased Assets	$	3
Interest on Lease Liabilities (1)	3
Variable	4
Total Lease Cost	$	10

⁽¹⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.

Operating lease cost for the three months ended March 31, 2019, was not material to TEP's financial position or results of operations.

As of March 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable real estate taxes and common area maintenance:

(in millions)	Operating Leases		Finance Leases (1)		Total
2019	$	1	$	173	$	174
2020	1		20		21
2021	1		—		1
2022	1		—		1
2023	1		—		1
Thereafter	5		—		5
Total Lease Payments	10		193		203
Less Imputed Interest	2		12		14
Total Lease Obligations	8		181		189
Less Current Portion	1		175		176
Total Non-Current Lease Obligations	$	7	$	6	$	13

⁽¹⁾  Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

The following table presents TEP's lease terms and discount rate related to its leases:

	March 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	7.1	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Three Months Ended
(in millions)	March 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	(4	)
Financing Cash Flows used for Finance Leases	(11		)
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities
Operating Leases	8

Operating cash flows from operating leases for the three months ended March 31, 2019, were not material.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to eight years. Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years.

Operating lease income for the three months ended March 31, 2019, was not material to TEP's results of operations. TEP's expected operating lease payments to be received at March 31, 2019, are $1 million in each of 2019 through 2023 and $1 million thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Operating Leases		Capital Leases
2019	$	1	$	187
2020	1		20
2021	1		—
2022	1		—
2023	1		—
Thereafter	5		—
Total Lease Payments	$	10	207
Less: Imputed Interest			14
Total Lease Obligations			193
Less: Current Portion			173
Total Non-Current Lease Obligations			$	20

Operating lease cost for the three months ended March 31,2018, was not material to TEP's results of operations.

LEASES

LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.

TEP leases generating facilities, land, rail cars, and communication tower space with remaining terms of one to 23 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s finance leases are included in Utility Plant Under Finance Leases, Accumulated Amortization of Finance Lease Assets, and current and non-current Finance Lease Obligations on the Condensed Consolidated Balance Sheets. TEP expects to exercise its option to purchase Gila River Unit 2 in December 2019. The purchase price is included in Current Liabilities—Finance Lease Obligations. Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options.

TEP’s operating leases are included on the balance sheet as follows:

(in millions)	March 31, 2019
Regulatory and Other Assets, Other	$	8
Current Liabilities, Other	1
Regulatory and Other Liabilities, Other	7

The following table presents the components of TEP’s lease cost:

	Three Months Ended
(in millions)	March 31, 2019
Finance
Amortization of Leased Assets	$	3
Interest on Lease Liabilities (1)	3
Variable	4
Total Lease Cost	$	10

⁽¹⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.

Operating lease cost for the three months ended March 31, 2019, was not material to TEP's financial position or results of operations.

As of March 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable real estate taxes and common area maintenance:

(in millions)	Operating Leases		Finance Leases (1)		Total
2019	$	1	$	173	$	174
2020	1		20		21
2021	1		—		1
2022	1		—		1
2023	1		—		1
Thereafter	5		—		5
Total Lease Payments	10		193		203
Less Imputed Interest	2		12		14
Total Lease Obligations	8		181		189
Less Current Portion	1		175		176
Total Non-Current Lease Obligations	$	7	$	6	$	13

⁽¹⁾  Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

The following table presents TEP's lease terms and discount rate related to its leases:

	March 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	7.1	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Three Months Ended
(in millions)	March 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	(4	)
Financing Cash Flows used for Finance Leases	(11		)
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities
Operating Leases	8

Operating cash flows from operating leases for the three months ended March 31, 2019, were not material.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to eight years. Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years.

Operating lease income for the three months ended March 31, 2019, was not material to TEP's results of operations. TEP's expected operating lease payments to be received at March 31, 2019, are $1 million in each of 2019 through 2023 and $1 million thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Operating Leases		Capital Leases
2019	$	1	$	187
2020	1		20
2021	1		—
2022	1		—
2023	1		—
Thereafter	5		—
Total Lease Payments	$	10	207
Less: Imputed Interest			14
Total Lease Obligations			193
Less: Current Portion			173
Total Non-Current Lease Obligations			$	20

Operating lease cost for the three months ended March 31,2018, was not material to TEP's results of operations.

LEASES

LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.

TEP leases generating facilities, land, rail cars, and communication tower space with remaining terms of one to 23 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s finance leases are included in Utility Plant Under Finance Leases, Accumulated Amortization of Finance Lease Assets, and current and non-current Finance Lease Obligations on the Condensed Consolidated Balance Sheets. TEP expects to exercise its option to purchase Gila River Unit 2 in December 2019. The purchase price is included in Current Liabilities—Finance Lease Obligations. Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options.

TEP’s operating leases are included on the balance sheet as follows:

(in millions)	March 31, 2019
Regulatory and Other Assets, Other	$	8
Current Liabilities, Other	1
Regulatory and Other Liabilities, Other	7

The following table presents the components of TEP’s lease cost:

	Three Months Ended
(in millions)	March 31, 2019
Finance
Amortization of Leased Assets	$	3
Interest on Lease Liabilities (1)	3
Variable	4
Total Lease Cost	$	10

⁽¹⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.

Operating lease cost for the three months ended March 31, 2019, was not material to TEP's financial position or results of operations.

As of March 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable real estate taxes and common area maintenance:

(in millions)	Operating Leases		Finance Leases (1)		Total
2019	$	1	$	173	$	174
2020	1		20		21
2021	1		—		1
2022	1		—		1
2023	1		—		1
Thereafter	5		—		5
Total Lease Payments	10		193		203
Less Imputed Interest	2		12		14
Total Lease Obligations	8		181		189
Less Current Portion	1		175		176
Total Non-Current Lease Obligations	$	7	$	6	$	13

⁽¹⁾  Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

The following table presents TEP's lease terms and discount rate related to its leases:

	March 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	7.1	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Three Months Ended
(in millions)	March 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	(4	)
Financing Cash Flows used for Finance Leases	(11		)
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities
Operating Leases	8

Operating cash flows from operating leases for the three months ended March 31, 2019, were not material.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to eight years. Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years.

Operating lease income for the three months ended March 31, 2019, was not material to TEP's results of operations. TEP's expected operating lease payments to be received at March 31, 2019, are $1 million in each of 2019 through 2023 and $1 million thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Operating Leases		Capital Leases
2019	$	1	$	187
2020	1		20
2021	1		—
2022	1		—
2023	1		—
Thereafter	5		—
Total Lease Payments	$	10	207
Less: Imputed Interest			14
Total Lease Obligations			193
Less: Current Portion			173
Total Non-Current Lease Obligations			$	20

Operating lease cost for the three months ended March 31,2018, was not material to TEP's results of operations.

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

COMMITMENTS

In addition to those reported in its 2018 Annual Report on Form 10-K, TEP entered into the following long-term commitment:

In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million. TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence in 2019 and be completed by December 2020.

CONTINGENCIES

Legal Matters

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP and are disclosed below.

Claims Related to San Juan Generating Station

WildEarth Guardians

In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to San Juan Coal Company (SJCC)) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, including: (i) failure to provide requisite public notice and participation, and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSMRE so the OSMRE may prepare a new Environmental Impact Statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSMRE's decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. In May 2018, the OSMRE released a draft EIS for public comment which was open through July 2018. On March 15, 2019, the OSMRE published a Notice of Availability in the Federal Register to announce the publication of the final EIS. The OSMRE issued a final record of decision on April 30, 2019. The final decision contemplates continued operation of the San Juan Mine. Public Service Company of New Mexico, operator of San Juan, is evaluating the final decision for any cost impacts that may be passed onto the participants of San Juan. TEP cannot currently predict the potential impact of these costs.

Mine Reclamation at Generation Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s estimated share of mine reclamation costs at all three mines is $65 million. Payments will be made through the expiration of the coal supply agreements, which expire between December 2019 and 2031. An aggregate liability balance related to final mine reclamation of $37 million as of March 31, 2019, and $36 million as of December 31, 2018 was reflected in current and non-current Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid out.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of March 31, 2019, there have been no such payment defaults under any of the participation agreements. The participation agreements expire in: (i) December 2019 at Navajo; (ii) 2022 at San Juan; (iii) 2041 at Four Corners; and (iv) 2046 at Luna.

Environmental Matters

TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance, in all material respects, with applicable environmental laws and regulations.

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EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,
(in millions)	2019			2018			2019		2018
Service Cost	$	3		$	4		$	1	$	1
Non-Service Cost (1)
Interest Cost	4			4			—		—
Expected Return on Plan Assets	(6		)	(7		)	—		—
Amortization of Net Loss	2			2			—		—
Net Periodic Benefit Cost	$	3		$	3		$	1	$	1

⁽¹⁾  The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:

	Level 1		Level 2			Level 3			Total
(in millions)	March 31, 2019
Assets
Cash Equivalents (1)	$	85	$	—		$	—		$	85
Restricted Cash (1)	14		—			—			14
Energy Derivative Contracts, Regulatory Recovery (2)	—		12			3			15
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			1			1
Total Assets	99		12			4			115
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(41		)	(10		)	(51		)
Total Liabilities	—		(41		)	(10		)	(51		)
Total Assets (Liabilities), Net	$	99	$	(29	)	$	(6	)	$	64

(in millions)	December 31, 2018
Assets
Cash Equivalents (1)	$	125	$	—		$	—		$	125
Restricted Cash (1)	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery (2)	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			2			2
Total Assets	140		10			2			152
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	140	$	(25	)	$	—		$	115

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.

⁽²⁾  Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	March 31, 2019
Derivative Assets
Energy Derivative Contracts	$	16		$	15		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(51		)	(15		)	—		(36		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

DERIVATIVE INSTRUMENTS

TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.

The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.

For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.

TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.

Cash Flow Hedges

To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense are not material to TEP's financial position or results of operations.

As of March 31, 2019, the total notional amount of the interest rate swap was $6 million.

Energy Derivative Contracts, Regulatory Recovery

TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:

	Three Months Ended March 31,
(in millions)	2019			2018
Unrealized Net Loss	$	(9	)	$	(18	)

Energy Derivative Contracts, No Regulatory Recovery

TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism.

Derivative Volumes

As of March 31, 2019, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

	March 31, 2019	December 31, 2018
Power Contracts GWh	2,933	1,743
Gas Contracts BBtu	144,825	146,933

Level 3 Fair Value Measurements

The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:

	Valuation Approach	Fair Value of					Unobservable Inputs	Range of Unobservable Inputs
		Assets		Liabilities
(in millions)	March 31, 2019
Forward Power Contracts	Market approach	$	4	$	(10	)	Market price per MWh	$	20.50	$	89.00

(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(8		)	—
Settlements	1			(1		)
End of Period	$	(6	)	$	1
Gains (Losses), Assets (Liabilities) Still Held	$	(7	)	$	—

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.

TEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.

TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.

The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $85 million as of March 31, 2019, compared with $41 million as of December 31, 2018. As of March 31, 2019, TEP had $10 million of cash posted as collateral to a counterparty to provide credit enhancement which was reflected in Current Assets—Other on the Condensed Consolidated Balance Sheet. As of April 30, 2019, there was no collateral posted as it was no longer required by the counterparty and the entire amount was returned to TEP. If the credit risk contingent features were triggered on March 31, 2019, TEP would have been required to post an additional $75 million of collateral of which $13 million relates to outstanding net payable balances for settled positions.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt:

	Fair Value Hierarchy	Face Value				Fair Value
(in millions)		March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,629	$	1,629	$	1,703	$	1,672

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of presentation

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2018 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

Variable interest entities

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

As of March 31, 2019, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

Restricted cash

Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.

Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations.

New accounting standards

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

Leases

TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance will be applied on a prospective basis to all new or modified land easements after January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 6 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables)

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of cash, cash equivalents, and restricted cash reported on the balance sheet

The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:

	Three Months Ended March 31,
(in millions)	2019		2018
Cash and Cash Equivalents	$	96	$	20
Restricted Cash included in:
Investments and Other Property	14		10
Current Assets—Other	1		2
Total Cash, Cash Equivalents, and Restricted Cash	$	111	$	32

Schedule of restricted cash

The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:

	Three Months Ended March 31,
(in millions)	2019		2018
Cash and Cash Equivalents	$	96	$	20
Restricted Cash included in:
Investments and Other Property	14		10
Current Assets—Other	1		2
Total Cash, Cash Equivalents, and Restricted Cash	$	111	$	32

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REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

Schedule of Regulatory Assets

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	4		$	—
ACC Refund (Reduction in Operating Revenues)	(7		)	(7		)
Amount Returned to Customers through Bill Credits	4			—
Regulatory Deferral	2			—
End of Period	$	3		$	(7	)

Schedule of Purchased Power and Fuel Adjustment Rates

The table below summarizes the PPFAC regulatory asset (liability) balance:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs	(3		)	2
PPFAC Refunds (Recoveries) (1)	(2		)	3
End of Period	$	(22	)	$	(4	)

⁽¹⁾  The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below:

($ in millions)	Remaining Recovery Period (years)	March 31, 2019		December 31, 2018
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	124	$	126
Early Generation Retirement Costs (1)	Various	70		72
Income Taxes Recoverable through Future Rates (2)	Various	46		47
Lost Fixed Cost Recovery	2	40		35
Derivatives (Note 9)	11	36		27
Final Mine Reclamation and Retiree Healthcare Costs (3)	19	27		29
Property Tax Deferrals (4)	1	24		23
Springerville Unit 1 Leasehold Improvements (5)	4	11		11
Other Regulatory Assets	Various	29		30
Total Regulatory Assets		407		400
Less Current Portion	1	117		107
Total Non-Current Regulatory Assets		$	290	$	293

Regulatory Liabilities
Income Taxes Payable through Future Rates (2)	Various	$	350	$	354
Net Cost of Removal (6)	Various	165		171
Renewable Energy Standard	Various	54		52
Purchased Power and Fuel Adjustment Clause	1	22		17
Deferred Investment Tax Credits (7)	Various	7		7
Other Regulatory Liabilities	Various	6		6
Total Regulatory Liabilities		604		607
Less Current Portion	1	101		95
Total Non-Current Regulatory Liabilities		$	503	$	512

⁽¹⁾  Includes the net book value and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10-year period in the 2019 Rate Case.

⁽²⁾  Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA.

⁽³⁾  Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038.

⁽⁴⁾  Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.

⁽⁵⁾  Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.

⁽⁶⁾  Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant which are not yet expended.

⁽⁷⁾  Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

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REVENUE (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:

	Three Months Ended March 31,
(in millions)	2019		2018
Retail	$	202	$	192
Wholesale	84		38
Other Services	24		23
Revenues from Contracts with Customers	310		253
Alternative Revenues	12		9
Other	11		13
Total Operating Revenues	$	333	$	275

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ACCOUNTS RECEIVABLE (Tables)

3 Months Ended

Mar. 31, 2019

Receivables [Abstract]

Accounts Receivable

The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2019			December 31, 2018
Customer (1)	$	85		$	99
Customer, Unbilled	35			45
Due from Affiliates (Note 5)	9			8
Other	18			25
Allowance for Doubtful Accounts	(5		)	(5		)
Accounts Receivable, Net	$	142		$	172

⁽¹⁾  Includes $6 million as of March 31, 2019, and $8 million as of December 31, 2018, of receivables related to revenue from derivative instruments.

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RELATED PARTY TRANSACTIONS (Tables)

3 Months Ended

Mar. 31, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Balances and Transactions

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2019		December 31, 2018
Receivables from Related Parties
UNS Electric	$	5	$	7
UNS Gas	1		1
UNS Energy	3		—
Total Due from Related Parties	$	9	$	8
Payables to Related Parties
SES	$	2	$	2
UNS Energy	1		1
UNS Electric	—		1
UNS Gas	1		1
Total Due to Related Parties	$	4	$	5

The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:

	Three Months Ended March 31,
(in millions)	2019		2018
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	1	$	2
Control Area Services, UNS Electric (2)	1		—
Common Costs, UNS Energy Affiliates (3)	5		4
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (4)	3		3
Corporate Services, UNS Energy (5)	1		2
Corporate Services, UNS Energy Affiliates (6)	1		2
Capacity Charges, UNS Gas	1		—

⁽¹⁾  TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.

⁽²⁾  TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.

⁽³⁾  Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

⁽⁴⁾  SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁵⁾  Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $2 million for the three months ended March 31, 2019 and 2018.

⁽⁶⁾  Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

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LEASES (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Assets And Liabilities, Lessee

TEP’s operating leases are included on the balance sheet as follows:

(in millions)	March 31, 2019
Regulatory and Other Assets, Other	$	8
Current Liabilities, Other	1
Regulatory and Other Liabilities, Other	7

Lease, Cost

The following table presents TEP's cash flow information related to its leases:

	Three Months Ended
(in millions)	March 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	(4	)
Financing Cash Flows used for Finance Leases	(11		)
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities
Operating Leases	8

The following table presents the components of TEP’s lease cost:

	Three Months Ended
(in millions)	March 31, 2019
Finance
Amortization of Leased Assets	$	3
Interest on Lease Liabilities (1)	3
Variable	4
Total Lease Cost	$	10

⁽¹⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.

Lessee, Operating Lease, Liability, Maturity

As of March 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable real estate taxes and common area maintenance:

(in millions)	Operating Leases		Finance Leases (1)		Total
2019	$	1	$	173	$	174
2020	1		20		21
2021	1		—		1
2022	1		—		1
2023	1		—		1
Thereafter	5		—		5
Total Lease Payments	10		193		203
Less Imputed Interest	2		12		14
Total Lease Obligations	8		181		189
Less Current Portion	1		175		176
Total Non-Current Lease Obligations	$	7	$	6	$	13

⁽¹⁾  Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

Finance Lease, Liability, Maturity

As of March 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable real estate taxes and common area maintenance:

(in millions)	Operating Leases		Finance Leases (1)		Total
2019	$	1	$	173	$	174
2020	1		20		21
2021	1		—		1
2022	1		—		1
2023	1		—		1
Thereafter	5		—		5
Total Lease Payments	10		193		203
Less Imputed Interest	2		12		14
Total Lease Obligations	8		181		189
Less Current Portion	1		175		176
Total Non-Current Lease Obligations	$	7	$	6	$	13

⁽¹⁾  Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

Schedule of Lease Term and Discount Rate

The following table presents TEP's lease terms and discount rate related to its leases:

	March 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	7.1	%
Operating Leases	4.1	%

Schedule of Future Minimum Rental Payments for Operating Leases

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Operating Leases		Capital Leases
2019	$	1	$	187
2020	1		20
2021	1		—
2022	1		—
2023	1		—
Thereafter	5		—
Total Lease Payments	$	10	207
Less: Imputed Interest			14
Total Lease Obligations			193
Less: Current Portion			173
Total Non-Current Lease Obligations			$	20

Schedule of Future Minimum Lease Payments for Capital Leases

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Operating Leases		Capital Leases
2019	$	1	$	187
2020	1		20
2021	1		—
2022	1		—
2023	1		—
Thereafter	5		—
Total Lease Payments	$	10	207
Less: Imputed Interest			14
Total Lease Obligations			193
Less: Current Portion			173
Total Non-Current Lease Obligations			$	20

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EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Cost

Net periodic benefit cost includes the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,
(in millions)	2019			2018			2019		2018
Service Cost	$	3		$	4		$	1	$	1
Non-Service Cost (1)
Interest Cost	4			4			—		—
Expected Return on Plan Assets	(6		)	(7		)	—		—
Amortization of Net Loss	2			2			—		—
Net Periodic Benefit Cost	$	3		$	3		$	1	$	1

⁽¹⁾  The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Financial Instruments Measured at Fair Value on Recurring Basis

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:

	Level 1		Level 2			Level 3			Total
(in millions)	March 31, 2019
Assets
Cash Equivalents (1)	$	85	$	—		$	—		$	85
Restricted Cash (1)	14		—			—			14
Energy Derivative Contracts, Regulatory Recovery (2)	—		12			3			15
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			1			1
Total Assets	99		12			4			115
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(41		)	(10		)	(51		)
Total Liabilities	—		(41		)	(10		)	(51		)
Total Assets (Liabilities), Net	$	99	$	(29	)	$	(6	)	$	64

(in millions)	December 31, 2018
Assets
Cash Equivalents (1)	$	125	$	—		$	—		$	125
Restricted Cash (1)	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery (2)	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			2			2
Total Assets	140		10			2			152
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	140	$	(25	)	$	—		$	115

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.

⁽²⁾  Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

Potential Offset of Assets by Counterparty Netting and Cash Collateral

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	March 31, 2019
Derivative Assets
Energy Derivative Contracts	$	16		$	15		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(51		)	(15		)	—		(36		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

Potential Offset of Liabilities by Counterparty Netting and Cash Collateral

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	March 31, 2019
Derivative Assets
Energy Derivative Contracts	$	16		$	15		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(51		)	(15		)	—		(36		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

Financial Impact of Energy Contracts

The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:

	Three Months Ended March 31,
(in millions)	2019			2018
Unrealized Net Loss	$	(9	)	$	(18	)

Derivative Volumes

As of March 31, 2019, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

	March 31, 2019	December 31, 2018
Power Contracts GWh	2,933	1,743
Gas Contracts BBtu	144,825	146,933

Fair Value Inputs, Assets, Quantitative Information Regarding Unobservable Inputs

The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:

	Valuation Approach	Fair Value of					Unobservable Inputs	Range of Unobservable Inputs
		Assets		Liabilities
(in millions)	March 31, 2019
Forward Power Contracts	Market approach	$	4	$	(10	)	Market price per MWh	$	20.50	$	89.00

(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

Level 3 Fair Value Reconciliation of Changes

The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:

	Three Months Ended March 31,
(in millions)	2019			2018
Beginning of Period	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(8		)	—
Settlements	1			(1		)
End of Period	$	(6	)	$	1
Gains (Losses), Assets (Liabilities) Still Held	$	(7	)	$	—

Face Value and Estimated Fair Value of Long-Term Debt

The following table includes the face value and estimated fair value of TEP's long-term debt:

	Fair Value Hierarchy	Face Value				Fair Value
(in millions)		March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,629	$	1,629	$	1,703	$	1,672

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands	3 Months Ended
	Mar. 31, 2019 mi² customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of retail customers | customer	427
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi²	1,155

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Cash and Cash Equivalents [Line Items]
Cash and Cash Equivalents	$ 96,441	$ 138,114	$ 20,000
Total Cash, Cash Equivalents, and Restricted Cash	110,843	$ 152,747	31,579	$ 49,501
Investments and Other Property
Cash and Cash Equivalents [Line Items]
Restricted Cash	14,000		10,000
Current Assets—Other
Cash and Cash Equivalents [Line Items]
Restricted Cash	$ 1,000		$ 2,000

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REGULATORY MATTERS (2019 Rate Case) (Details) - Subsequent Event - Arizona Corporation Commission $ in Millions	Apr. 01, 2019 USD ($)
Non-fuel Component of Base Rate
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase	$ 115
Non-fuel base rate increase (percentage)	7.80%
Original cost rate base (percentage)	7.68%
Original cost rate base	$ 2,700
Fuel Component of Base Rate
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase	(39)
Revenue Component of Base Rate
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase	$ 76

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REGULATORY MATTERS (Federal Tax Legislation) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Roll Forward]
Beginning of Period	$ 400,000		$ 400,000
Regulatory Deferral	1,707	$ 0
End of Period	407,000			$ 400,000
Arizona Corporation Commission
Public Utilities, General Disclosures [Line Items]
Change in tax rate, refund to customers, net of amortization				33,000
Arizona Corporation Commission | Revenue Refund
Regulatory Assets [Roll Forward]
Beginning of Period	4,000	0	4,000	0
ACC Refund (Reduction in Operating Revenues)	(7,000)	(7,000)
Amount Returned to Customers through Bill Credits	4,000	0
Regulatory Deferral	2,000	0
End of Period	$ 3,000	$ (7,000)		$ 4,000
Arizona Corporation Commission | Scenario, Forecast
Regulatory Assets [Roll Forward]
Amount Returned to Customers through Bill Credits			$ 34,000

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REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended		12 Months Ended
	Feb. 28, 2019	Jan. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2025	Dec. 31, 2019
Regulatory Liabilities [Roll Forward]
Beginning of Period			$ 607			$ 607
End of Period			604
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Roll Forward]
Beginning of Period		$ 9	17	$ 9		$ 17
Deferred Fuel and Purchased Power Costs			(3)	2
PPFAC Refunds (Recoveries)			(2)	3
End of Period			$ 22	4
Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified			12 months
Renewable Energy Standard
Regulatory Liabilities [Roll Forward]
Approved spending budget		$ 54
Renewable Energy Standard | Scenario, Forecast
Regulatory Liabilities [Roll Forward]
Renewable Energy Target Percentage					15.00%	9.00%
Distributed generation requirement percent of target percentage (percentage)					30.00%
Demand Side Management
Regulatory Liabilities [Roll Forward]
Recovery revenue			$ 2	2
Energy Efficiency Standards
Regulatory Liabilities [Roll Forward]
Approved recovery of spending budget	$ 23
Lost Fixed Cost Recovery
Regulatory Liabilities [Roll Forward]
Recovery revenue			$ 10	$ 8
Cap on increase in lost fixed cost recovery rate (percentage)			2.00%

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REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 407,000	$ 400,000
Less Current Portion	117,237	106,725
Total Non-Current Regulatory Assets	289,566	293,078
Pension and Other Postretirement Benefits
Regulatory Assets [Line Items]
Total Regulatory Assets	124,000	126,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	70,000	72,000
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 46,000	47,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	2 years
Total Regulatory Assets	$ 40,000	35,000
Derivatives (Note 9)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	11 years
Total Regulatory Assets	$ 36,000	27,000
Final Mine Reclamation and Retiree Healthcare Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	19 years
Total Regulatory Assets	$ 27,000	29,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 24,000	23,000
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	4 years
Total Regulatory Assets	$ 11,000	11,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 29,000	$ 30,000

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REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 604,000	$ 607,000
Less Current Portion	101,219	95,094
Total Non-Current Regulatory Liabilities	503,259	512,425
Income Taxes Payable through Future Rates
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	350,000	354,000
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	165,000	171,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 54,000	52,000
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 22,000	17,000	$ 4,000	$ 9,000
Deferred Investment Tax Credits
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	7,000	7,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 6,000	$ 6,000

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REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details)	3 Months Ended
	Mar. 31, 2019
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Navajo and Sundt Units 1 and 2
Regulatory Assets [Line Items]
Useful life (in years)	10 years
Property Tax Pay As You Go or Cash Basis
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	6 months
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Useful life (in years)	10 years
Remaining Recovery Period (years)	4 years

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REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 310,000	$ 253,000
Alternative Revenues	12,000	9,000
Other	11,000	13,000
Total Operating Revenues	333,003	275,091
Retail
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	202,000	192,000
Wholesale
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	84,000	38,000
Other Services
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 24,000	$ 23,000

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ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts	$ (5,000)	$ (5,000)
Accounts Receivable, Net	142,339	172,367
Customer
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	85,000	99,000
Customer | Derivatives (Note 9)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	6,000	8,000
Customer | Due from Affiliates
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	9,000	8,000
Customer | Customer, Unbilled
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	35,000	45,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 18,000	$ 25,000

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	$ 9,000		$ 8,000
Due to related parties	4,000		5,000
Supplemental workforce	140,398	$ 90,211
Transmission Revenues, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Revenue from related party	1,000	2,000
Control Area Services, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Control area services	1,000	0
Common Costs, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Common costs	5,000	4,000
Supplemental Workforce, SES
Related Party Transaction, Due to/from Related Party [Abstract]
Supplemental workforce	3,000	3,000
Corporate Services, UNS Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate services	$ 1,000	2,000
Massachusetts Formula - TEP's allocation (percentage)	83.00%
Management fee	$ 2,000	2,000
Corporate Services, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate services	1,000	2,000
Capacity Charges, UNS Gas
Related Party Transaction, Due to/from Related Party [Abstract]
Capacity charges	1,000	$ 0
UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	5,000		7,000
Due to related parties	0		1,000
UNS Gas
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	1,000		1,000
Due to related parties	1,000		1,000
Uns Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	3,000		0
Due to related parties	1,000		1,000
SES
Related Party Transaction, Due to/from Related Party [Abstract]
Due to related parties	$ 2,000		$ 2,000

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LEASES (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) contract option
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Renewal term	15 years
Number of contracts | contract	2
Lessor, Operating Lease, Payments, Fiscal Year Maturity
Remainder of 2019	$ 1
2020	1
2021	1
2022	1
2023	1
Thereafter	$ 1
Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Number of renewal options | option	1
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Minimum | Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Remaining lease term	3 years
Renewal term	2 years
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	23 years
Maximum | Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Remaining lease term	8 years
Renewal term	10 years

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LEASES (Assets and Liabilities) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Leases [Abstract]
Regulatory and Other Assets, Other	$ 8
Current Liabilities, Other	1
Regulatory and Other Liabilities, Other	$ 7

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LEASES (Lease Cost) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Amortization of Leased Assets	$ 3
Interest on Lease Liabilities	3
Variable	4
Total Lease Cost	$ 10

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LEASES (Lease Liability) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Operating Leases
2019	$ 1
2020	1
2021	1
2022	1
2023	1
Thereafter	5
Total Lease Payments	10
Less Imputed Interest	2
Total Lease Obligations	8
Less Current Portion	1
Total Non-Current Lease Obligations	7
Finance Leases
2019	173
2020	20
2021	0
2022	0
2023	0
Thereafter	0
Total Lease Payments	193
Less Imputed Interest	12
Total Lease Obligations	181
Less Current Portion	175
Total Non-Current Lease Obligations	6
Total
2019	174
2020	21
2021	1
2022	1
2023	1
Thereafter	5
Total Lease Payments	203
Less Imputed Interest	14
Total Lease Obligations	189
Less Current Portion	176
Total Non-Current Lease Obligations	$ 13
GIla River Unit 2
Lessee, Lease, Description [Line Items]
Term of contract	20 months

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LEASES (Term and Rate) (Details)	Mar. 31, 2019
Leases [Abstract]
Weighted-Average Remaining Lease Term (years), Finance Lease	1 year
Weighted-Average Remaining Lease Term (years), Operating Lease	12 years
Weighted-Average Discount Rate, Finance Lease	7.10%
Weighted-Average Discount Rate, Operating Lease	4.10%

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LEASES (Cash Flows) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating Cash Flows used for Finance Leases	$ (4)
Financing Cash Flows used for Finance Leases	(11)
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities, Operating Lease	$ 8

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LEASES (Future Minimum Lease Payments) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Operating Leases
2019		$ 1,000
2020		1,000
2021		1,000
2022		1,000
2023		1,000
Thereafter		5,000
Total Lease Payments		10,000
Capital Leases
2019		187,000
2020		20,000
2021		0
2022		0
2023		0
Thereafter		0
Capital Leases, Future Minimum Payments Due		207,000
Less: Imputed Interest		14,000
Total Lease Obligations		193,000
Less: Current Portion	$ 175,202	172,510
Total Non-Current Lease Obligations	$ 6,192	$ 19,773

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COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Contractual obligation	$ 370

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COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - Navajo, San Juan, Four Corners $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) mine	Dec. 31, 2018 USD ($)
Commitments And Contingencies [Line Items]
Number of mines expected to be reclaimed | mine	3
Share of reclamation costs anticipated	$ 65
Other Liabilities
Commitments And Contingencies [Line Items]
Environmental exit costs, costs accrued to date	$ 37	$ 36

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COMMITMENTS AND CONTINGENCIES (Performance guarantees) (Details) - Performance Guarantee	Mar. 31, 2019 USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations, current carrying value	$ 0
Navajo, San Juan, Luna
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure, undiscounted	0
Four Corner
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure, undiscounted	$ 250,000,000

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Pension Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 3	$ 4
Interest Cost	4	4
Expected Return on Plan Assets	(6)	(7)
Amortization of Net Loss	2	2
Net Periodic Benefit Cost	3	3
Other Postretirement Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1
Interest Cost	0	0
Expected Return on Plan Assets	0	0
Amortization of Net Loss	0	0
Net Periodic Benefit Cost	$ 1	$ 1

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Recurring - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Assets
Cash Equivalents	$ 85	$ 125
Restricted Cash	14	15
Energy Derivative Contract Assets - Regulatory Recovery	15	10
Energy Derivative Contract Assets - No Regulatory Recovery	1	2
Total Assets	115	152
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(51)	(37)
Total Liabilities	(51)	(37)
Total Assets (Liabilities), Net	64	115
Level 1
Assets
Cash Equivalents	85	125
Restricted Cash	14	15
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	99	140
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Total Liabilities	0	0
Total Assets (Liabilities), Net	99	140
Level 2
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	12	10
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	12	10
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(41)	(35)
Total Liabilities	(41)	(35)
Total Assets (Liabilities), Net	(29)	(25)
Level 3
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	3	0
Energy Derivative Contract Assets - No Regulatory Recovery	1	2
Total Assets	4	2
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(10)	(2)
Total Liabilities	(10)	(2)
Total Assets (Liabilities), Net	$ (6)	$ 0

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative Contracts - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivative Assets
Gross Amount Recognized in the Balance Sheets	$ 16	$ 12
Counterparty Netting of Energy Contracts	15	11
Cash Collateral Received/Posted	0	0
Net Amount	1	1
Derivative Liabilities
Gross Amount Recognized in the Balance Sheets	(51)	(37)
Counterparty Netting of Energy Contracts	(15)	(11)
Cash Collateral Received/Posted	0	0
Net Amount	$ (36)	$ (26)

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Interest Rate Swap
Derivative [Line Items]
Derivative liability, notional amount	$ 6

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Percent of long-term trading contract gains shared with ratepayers (percentage)	10.00%
Energy Derivative Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Loss	$ (9)	$ (18)

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Mar. 31, 2019 GWh BTU	Dec. 31, 2018 GWh BTU
Power Contracts GWh
Derivative Volume [Line Items]
Derivatives volumes | GWh	2,933	1,743
Gas Contracts BBtu
Derivative Volume [Line Items]
Derivatives volumes | BTU	144,824,622,000,000	146,933,000,000,000

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 - Forward Power Contracts $ in Millions	Mar. 31, 2019 USD ($) $ / megawatt_hour	Dec. 31, 2018 USD ($) $ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative assets | $	$ 4	$ 3
Derivative liabilities | $	$ (10)	$ (2)
Minimum
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh (usd per MWh) | $ / megawatt_hour	20.50	16.80
Maximum
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh (usd per MWh) | $ / megawatt_hour	89.00	47.05

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning of Period	$ 1	$ 2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(8)	0
Settlements	1	(1)
End of Period	(6)	1
Gains (Losses), Assets (Liabilities) Still Held	$ (7)	$ 0

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Apr. 30, 2019	Mar. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale		$ 85,000,000	$ 41,000,000
Collateral posted		10,000,000
Additional collateral required to post if credit-risk contingent features are triggered		75,000,000
Amount relating to outstanding net payable balances for settled positions
Derivative [Line Items]
Additional collateral required to post if credit-risk contingent features are triggered		$ 13,000,000
Subsequent Event
Derivative [Line Items]
Collateral posted	$ 0

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Face Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities, Face Value	$ 1,629	$ 1,629
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities, Fair Value	$ 1,703	$ 1,672