Tucson Electric Power 10-Q 1 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

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

CONDENSED CONSOLIDATED STATEMEN

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

CONDENSED CONSOLIDATED STATEM_2

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

CONDENSED CONSOLIDATED STATEM_3

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

CONDENSED CONSOLIDATED BALANCE

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

CONDENSED CONSOLIDATED STATEM_4

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

CONDENSED CONSOLIDATED BALANC_2

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

CONDENSED CONSOLIDATED STATEM_5

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)

NATURE OF OPERATIONS AND FINANC

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.

REGULATORY MATTERS

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.

REVENUE

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

ACCOUNTS RECEIVABLE

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.

RELATED PARTY TRANSACTIONS

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.

LEASES

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 no t 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 no t 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 no t 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 no t 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 no t 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 no t 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 no t 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 no t 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 no t material to TEP's results of operations.

COMMITMENTS AND CONTINGENCIES

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.

EMPLOYEE BENEFIT PLANS

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.

FAIR VALUE MEASUREMENTS AND DER

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

NATURE OF OPERATIONS AND FINA_2

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.

NATURE OF OPERATIONS AND FINA_3

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

REGULATORY MATTERS (Tables)

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.

REVENUE (Tables)

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

ACCOUNTS RECEIVABLE (Tables)

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.

RELATED PARTY TRANSACTIONS (Tab

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.

LEASES (Tables)

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

EMPLOYEE BENEFIT PLANS (Tables)

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.

FAIR VALUE MEASUREMENTS AND D_2

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

NATURE OF OPERATIONS AND FINA_4

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands	3 Months Ended
	Mar. 31, 2019mi²customer
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

NATURE OF OPERATIONS AND FINA_5

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

REGULATORY MATTERS (2019 Rate C

REGULATORY MATTERS (2019 Rate Case) (Details) - Subsequent Event - Arizona Corporation Commission $ in Millions	Apr. 01, 2019USD ($)
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

REGULATORY MATTERS (Federal Tax

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

REGULATORY MATTERS (Cost Recove

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%

REGULATORY MATTERS (Regulatory

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

REGULATORY MATTERS (Regulator_2

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

REGULATORY MATTERS (Regulator_3

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

REVENUE (Details)

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

ACCOUNTS RECEIVABLE (Details)

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

RELATED PARTY TRANSACTIONS (Det

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

LEASES (Narrative) (Details)

LEASES (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)contractoption
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

LEASES (Assets and Liabilities)

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

LEASES (Lease Cost) (Details)

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

LEASES (Lease Liability) (Detai

LEASES (Lease Liability) (Details) $ in Millions	Mar. 31, 2019USD ($)
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

LEASES (Term and Rate) (Details

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%

LEASES (Cash Flows) (Details)

LEASES (Cash Flows) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)
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

LEASES (Future Minimum Lease Pa

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

COMMITMENTS AND CONTINGENCIES (

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

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - Navajo, San Juan, Four Corners $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)mine	Dec. 31, 2018USD ($)
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

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Performance guarantees) (Details) - Performance Guarantee	Mar. 31, 2019USD ($)
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

EMPLOYEE BENEFIT PLANS (Details

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

FAIR VALUE MEASUREMENTS AND D_3

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

FAIR VALUE MEASUREMENTS AND D_4

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)

FAIR VALUE MEASUREMENTS AND D_5

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

FAIR VALUE MEASUREMENTS AND D_6

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)

FAIR VALUE MEASUREMENTS AND D_7

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Mar. 31, 2019GWhBTU	Dec. 31, 2018GWhBTU
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

FAIR VALUE MEASUREMENTS AND D_8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 - Forward Power Contracts $ in Millions	Mar. 31, 2019USD ($)$ / megawatt_hour	Dec. 31, 2018USD ($)$ / 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	47.05

FAIR VALUE MEASUREMENTS AND D_9

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

FAIR VALUE MEASUREMENTS AND _10

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

FAIR VALUE MEASUREMENTS AND _11

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