Tucson Electric Power 10-Q 2 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 01, 2017
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	100,122
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		32,139,434

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating Revenues
Retail	$ 199,506	$ 203,953
Wholesale	42,538	16,631
Other	26,338	25,113
Total Operating Revenues	268,382	245,697
Operating Expenses
Fuel	66,728	62,678
Purchased Power	24,295	19,958
Transmission and Other PPFAC Recoverable Costs	8,899	5,178
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(8,190)	6,795
Total Fuel and Purchased Power	91,732	94,609
Operations and Maintenance	82,141	84,999
Depreciation	38,157	35,632
Amortization	5,402	5,476
Taxes Other Than Income Taxes	13,800	13,030
Total Operating Expenses	231,232	233,746
Operating Income	37,150	11,951
Other Income (Deductions)
Interest Income	93	38
Other Income	9,020	1,393
Other Expense	(761)	(423)
Appreciation in Value of Investments	734	200
Total Other Income (Deductions)	9,086	1,208
Interest Expense
Long-Term Debt	15,436	15,491
Capital Leases	664	858
Other Interest Expense	215	123
Interest Capitalized	(530)	(464)
Total Interest Expense	15,785	16,008
Income (Loss) Before Income Taxes	30,451	(2,849)
Income Tax Expense (Benefit)	9,692	(2,147)
Net Income (Loss)	$ 20,759	$ (702)

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 20,759	$ (702)
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges: Net of Income Tax Expense of $74 and $6	119	9
Supplemental Executive Retirement Plan Adjustments: Net of income Tax Expense of $43 and $35	70	56
Total Other Comprehensive Income Net of Tax	189	65
Total Comprehensive Income (Loss)	$ 20,948	$ (637)

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Tax Expense related to Change in Fair Value of Cash Flow Hedges	$ 74	$ 6
Tax Expense related to Supplemental Executive Retirement Plan Adjustments	$ 43	$ 35

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Cash Flows [Abstract]
Net Income (Loss)	$ 20,759	$ (702)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation Expense	38,157	35,632
Amortization Expense	5,402	5,476
Amortization of Debt Issuance Costs	589	726
Use of Renewable Energy Credits for Compliance	5,385	3,518
Deferred Income Taxes	9,709	(2,149)
Pension and Other Postretirement Benefits Expense	4,010	3,835
Pension and Other Postretirement Benefits Funding	(1,088)	(1,582)
Allowance for Equity Funds Used During Construction	(1,358)	(1,171)
FERC Transmission Refund Payable	180	13,314
Changes in Current Assets and Current Liabilities:
Accounts Receivable	15,875	29,780
Materials, Supplies, and Fuel Inventory	1,051	2,593
Regulatory Assets	(6,063)	(5,680)
Accounts Payable and Accrued Charges	11,409	150
Regulatory Liabilities	(7,342)	5,294
Other, Net	1,373	5,696
Net Cash Flows—Operating Activities	98,048	94,730
Cash Flows from Investing Activities
Capital Expenditures	(78,809)	(72,837)
Purchase Intangibles, Renewable Energy Credits	(11,051)	(7,701)
Contributions in Aid of Construction	929	(456)
Net Cash Flows—Investing Activities	(88,931)	(80,994)
Cash Flows from Financing Activities
Payments of Capital Lease Obligations	(10,310)	(9,039)
Other, Net	285	30
Net Cash Flows—Financing Activities	(10,025)	(9,009)
Net Increase (Decrease) in Cash and Cash Equivalents	(908)	4,727
Cash and Cash Equivalents, Beginning of Period	35,962	55,684
Cash and Cash Equivalents, End of Period	$ 35,054	$ 60,411

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Utility Plant
Plant in Service	$ 5,780,279	$ 5,975,139
Utility Plant Under Capital Leases	167,413	167,413
Construction Work in Progress	163,155	129,955
Total Utility Plant	6,110,847	6,272,507
Accumulated Depreciation and Amortization	(2,169,607)	(2,385,053)
Accumulated Amortization of Capital Lease Assets	(106,323)	(104,648)
Total Utility Plant, Net	3,834,917	3,782,806
Investments and Other Property	45,918	45,020
Current Assets
Cash and Cash Equivalents	35,054	35,962
Accounts Receivable, Net	108,889	124,934
Fuel Inventory	24,631	25,887
Materials and Supplies	99,379	97,126
Regulatory Assets	59,530	56,340
Derivative Instruments	3,914	4,966
Other	12,746	13,793
Total Current Assets	344,143	359,008
Regulatory and Other Assets
Regulatory Assets	220,827	225,453
Derivative Instruments	111	330
Other	40,737	37,372
Total Regulatory and Other Assets	261,675	263,155
Total Assets	4,486,653	4,449,989
Capitalization
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2017 and December 31, 2016)	1,296,539	1,296,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	294,167	273,408
Accumulated Other Comprehensive Loss	(4,366)	(4,555)
Total Common Stock Equity	1,579,983	1,559,035
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2017 and December 31, 2016)	0	0
Capital Lease Obligations	28,164	39,267
Long-Term Debt, Net	1,453,409	1,453,072
Total Capitalization	3,061,556	3,051,374
Current Liabilities
Capital Lease Obligations	52,263	51,765
Accounts Payable	87,469	89,797
Accrued Taxes Other than Income Taxes	49,948	37,639
Accrued Employee Expenses	18,966	29,465
Accrued Interest	13,121	14,508
Regulatory Liabilities	69,199	76,069
Customer Deposits	26,473	25,778
Derivative Instruments	2,930	2,641
Other	23,021	17,837
Total Current Liabilities	343,390	345,499
Regulatory and Other Liabilities
Deferred Income Taxes, Net	539,908	529,148
Regulatory Liabilities	308,825	300,700
Pension and Other Postretirement Benefits	132,840	131,630
Derivative Instruments	6,687	2,629
Other	93,447	89,009
Total Regulatory and Other Liabilities	1,081,707	1,053,116
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 4,486,653	$ 4,449,989

CONDENSED CONSOLIDATED BALANCE7

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (Unaudited) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common Stock, No Par Value ($ per share)	$ 0	$ 0
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, No Par Value ($ per share)	$ 0	$ 0
Preferred Stock, Shares Authorized (in shares)	1,000,000	1,000,000
Preferred Stock, Shares Outstanding (in shares)	0	0

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited) - USD ($) $ in Thousands	Total	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
Balances at Dec. 31, 2015	$ 1,474,935	$ 1,296,539	$ (6,357)	$ 189,317	$ (4,564)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income (Loss)	(702)			(702)
Other Comprehensive Income, Net of Tax	65				65
Balances at Mar. 31, 2016	1,483,951	1,296,539	(6,357)	198,268	(4,499)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Adoption of ASU, Cumulative Effect Adjustment	9,653			9,653
Balances at Dec. 31, 2016	1,559,035	1,296,539	(6,357)	273,408	(4,555)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income (Loss)	20,759			20,759
Other Comprehensive Income, Net of Tax	189				189
Balances at Mar. 31, 2017	$ 1,579,983	$ 1,296,539	$ (6,357)	$ 294,167	$ (4,366)

NATURE OF OPERATIONS AND FINANC

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	3 Months Ended
	Mar. 31, 2017
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 422,000 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 Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis Inc. (Fortis). BASIS OF PRESENTATION TEP's condensed consolidated financial statements and disclosures are presented in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) 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's proportionate share of jointly owned facilities is recorded in Utility Plant on the Condensed Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included 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 its 2016 Annual Report on Form 10-K. The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation 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. TEP's income statement reflects a reclassification related to wholesale contracts. The Condensed Consolidated Income Statements reflect a reclassification between Wholesale Revenues and Purchased Power Expense of $2 million for the three months ended March 31, 2016 . Management does not believe the reclassification is material to the previously issued financial statements. Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (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 Purchased Power Agreements (PPA) 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 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, 2017 , 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 retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS Effective January 1, 2016, TEP adopted accounting guidance that simplifies the accounting for share-based payment accounting. The guidance requires that excess tax benefits and tax deficiencies be recorded as an income tax benefit or expense on the statement of income and eliminates the requirement that excess tax benefits be realized before companies can recognize them. On adoption, using the modified retrospective method of transition, TEP recorded a cumulative effect adjustment of $10 million to increase retained earnings and decrease deferred income taxes related to prior period unrecognized excess tax benefits. The impact on the income statement and the statement of cash flows were not significant. TEP elected to recognize forfeitures when they occur. Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principle is not expected to have any impact on TEP as the Company recovers the cost of inventory in rates.

REGULATORY MATTERS

REGULATORY MATTERS	3 Months Ended
	Mar. 31, 2017
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (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. 2017 RATE ORDER In February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017 (2017 Rate Order). Provisions of the 2017 Rate Order include, but are not limited to: • a non-fuel base rate increase of $81.5 million , which includes $15 million of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station (Springerville) purchased by TEP in September 2016; • a 7.04% return on original cost rate base, which includes a cost of equity component of 9.75% and a cost of debt component of 4.32% ; and • adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for Unit 1 of San Juan Generating Station (San Juan). The ACC deferred matters related to net metering and rate design for new distributed generation (DG) customers to a second phase of TEP’s rate case proceedings (Phase 2), which is expected to be completed by end of 2017. TEP cannot predict the outcome of these proceedings. 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 Purchased Power and Fuel Adjustment Clause (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 rates designed to allow a regulated utility to recover its costs of providing services and an opportunity to earn a reasonable return on its investment (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 PPFAC bank balance was over-collected by $31 million as of March 31, 2017 and by $38 million as of December 31, 2016 . In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected balance to customers. The table below presents TEP's PPFAC rates approved by the ACC: Period Cents per kWh March 2017 through March 2018 (0.20 ) May 2016 through February 2017 0.15 April 2015 through April 2016 0.68 Renewable Energy Standard The ACC’s Renewable Energy Standard (RES) requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. In March 2017, the ACC approved TEP's 2017 RES implementation plan of $54 million , which was partially offset by applying approximately $2 million of previously recovered carryover funds. TEP has been approved to recover the remaining $52 million through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer installed DG; (iii) depreciation and a return on a company-owned solar project; and (iv) various other program costs. TEP expects to recover less than $1 million of revenue in 2017 through the RES surcharge as a return on company-owned solar projects. This amount reflects the return and related recovery on projects that are not included in TEP’s Retail Rates. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case. The percentage of retail kilowatt-hour (kWh) sales attributable to the 2016 RES renewable energy requirement was 10% , which exceeded the overall 2016 requirement of 6% . Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG renewable energy credits, which are used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2016 and 2017 residential DG requirement. Energy Efficiency Standards TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency Standards (EE Standards). The EE Standards provide for a DSM surcharge for regulated utilities 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, with $2 million recorded in 2017 and $2 million in 2016 . This performance incentive is included in Retail Revenues on the Condensed Consolidated Statements of Income. In February 2016, the ACC approved TEP’s 2016 energy efficiency implementation plan which included a budget of approximately $22 million to be funded in part with an over-collected DSM bank balance of $8 million and a DSM surcharge designed to collect the remaining $14 million from retail customers. Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism. TEP notified the ACC that it would not file a 2017 implementation plan and will continue its 2016 plan through the end of 2017 without a change to the previously approved energy efficiency programs or budget. In order to fund the approved implementation plan budget during 2017, in March 2017, TEP filed an application with the ACC to increase the DSM surcharge by approximately $7 million . TEP cannot predict if or when the ACC will consider its application. TEP plans to file its 2018 implementation plan in June 2017. 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 meeting DG targets. 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 the 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 a regulatory asset and recognized LFCR revenues of $6 million and $5 million in the three months ended March 31, 2017 and 2016 , respectively. LFCR revenues are included in Retail Revenues on the Condensed Consolidated Statements of Income. FERC COMPLIANCE In 2016, the FERC issued orders relating to certain late-filed transmission service agreements (TSAs), which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. See Note 6 for additional information related to FERC compliance associated with these transmission contracts. REGULATORY ASSETS AND LIABILITIES Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of the leasehold improvements at Springerville Unit 1 and the coal handling facilities at Sundt, 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, TEP does not pay a return on regulatory liabilities. The regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: (dollars in millions) Remaining Recovery Period (years) March 31, 2017 December 31, 2016 Regulatory Assets Pension and Other Postretirement Benefits (Note 7) Various $ 126 $ 128 Final Mine Reclamation and Retiree Health Care Costs (1) 20 29 27 Income Taxes Recoverable through Future Rates Various 29 29 Lost Fixed Cost Recovery 1 27 23 Property Tax Deferrals 1 23 23 Springerville Unit 1 Leasehold Improvements (2) 6 15 17 Sundt Coal Handling Facilities (3) N/A — 14 Other Regulatory Assets Various 32 20 Total Regulatory Assets 281 281 Less Current Portion 1 60 56 Total Non-Current Regulatory Assets $ 221 $ 225 Regulatory Liabilities Net Cost of Removal for Interim Retirements (4) Various $ 280 $ 270 Renewable Energy Standard Various 34 32 Purchased Power and Fuel Adjustment Clause 1 31 38 Deferred Investment Tax Credits Various 23 23 Other Regulatory Liabilities Various 10 14 Total Regulatory Liabilities 378 377 Less Current Portion 1 69 76 Total Non-Current Regulatory Liabilities $ 309 $ 301 (1) Final Mine Reclamation and Retiree Health Care Costs represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and Navajo Generating Station (Navajo). TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037 . (2) Springerville Unit 1 Leasehold Improvements represent 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 amortization period. (3) In March 2016, TEP notified the Environmental Protection Agency (EPA) of its decision to permanently eliminate coal as a fuel source, and transferred the net book value (NBV) of the Sundt Coal Handling Facilities to a regulatory asset. The ACC authorized TEP to apply excess depreciation reserves against the unrecovered NBV in the 2017 Rate Order. As a result, TEP transferred $14 million from Regulatory Assets to Accumulated Depreciation on the Condensed Consolidated Balance Sheets. (4) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	3 Months Ended
	Mar. 31, 2017
Accounts Receivable, Net [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, 2017 December 31, 2016 Customer $ 66 $ 74 Due from Affiliates (Note 4) 5 9 Unbilled 30 34 Other 13 13 Allowance for Doubtful Accounts (5 ) (5 ) Accounts Receivable, Net $ 109 $ 125

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy Affiliates). These transactions include the sale and purchase of power and transmission services, common cost allocations, and 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, 2017 December 31, 2016 Receivables from Related Parties UNS Electric $ 4 $ 7 UNS Gas 1 2 Total Due from Related Parties $ 5 $ 9 Payables to Related Parties SES $ 2 $ 2 UNS Energy 1 — Total Due to Related Parties $ 3 $ 2 The following table presents the related party transactions included in the income statement: Three Months Ended March 31, (in millions) 2017 2016 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 1 $ 1 Control Area Services, UNS Electric (2) 1 — Common Costs, UNS Energy Affiliates (3) 4 3 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 3 4 Corporate Services, UNS Energy (5) 1 2 Corporate Services, UNS Energy Affiliates (6) 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 are 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 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis management fees. For the three months ended March 31, 2017 and 2016 , these costs included Fortis management fees of $1 million . (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. CONTRIBUTION FROM PARENT UNS Energy made no equity contributions to TEP in the three months ended March 31, 2017 or 2016 . DIVIDENDS PAID TO PARENT TEP did not declare or pay dividends to UNS Energy in the three months ended March 31, 2017 or 2016 .

DEBT, CREDIT FACILITY, AND CAPI

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS There have been no significant changes to TEP's debt, credit facility, or capital lease obligations from those reported in its 2016 Annual Report on Form 10-K, except as noted below. As of March 31, 2017 , there was $250 million available under the revolving credit commitments and LOC facilities. As of May 1, 2017 , TEP had $235 million available under its revolving credit commitments and LOC facilities. COVENANT COMPLIANCE As of March 31, 2017 , TEP was in compliance with the terms of its credit and long-term debt agreements.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS There have been no significant changes to TEP's long-term commitments from those reported in its 2016 Annual Report on Form 10-K. 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 condensed 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 Four Corners Generating Station Endangered Species Act On April 20, 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Arizona against the Office of Surface Mining (OSM) and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the National Environmental Policy Act (NEPA) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the adjacent Navajo Mine. In addition, the lawsuit alleges that these federal agencies violated both the ESA and the NEPA in providing the federal approvals necessary to extend operations at Four Corners and Navajo Mine past July 6, 2016. The lawsuit seeks various forms of relief, including a finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo Mine pending compliance with NEPA. In July 2016, the defendants answered the complaint and Arizona Public Service Company (APS), the operator of Four Corners, filed a motion to intervene in this matter. APS’ motion was granted in August 2016. Briefing on the merits is expected to extend through May 2017. In September 2016, Navajo Transitional Energy Company, LLC (NTEC), the company that owns the Navajo Mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Claims Related to San Juan Generating Station WildEarth Guardians In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the OSM challenging federal administrative decisions issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by the OSM. Of the claims for relief in the WEG Petition, two concern San Juan Coal Company’s (SJCC) San Juan mine. WEG’s allegations concerning the San Juan mine arise from the OSM administrative actions in 2008. WEG alleges various NEPA violations against the OSM, including, but not limited to, the OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated the NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with the NEPA has been demonstrated, and enjoining operations at the affected mines. SJCC intervened in this matter. SJCC 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 proceeding. On July 18, 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM 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 federal defendants’ motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provided that the OSM’s decision approving the mining plan will remain in effect during this process. The order further provides that if the EIS is not completed by August 31, 2019, then an order vacating the approved mine plan will become immediately effective, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Mine Reclamation at Generating Facilities Not Operated by TEP TEP pays ongoing reclamation mine 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 share of reclamation costs at all three mines is expected to be $61 million upon expiration of the coal supply agreements, which expire between 2019 and 2031 . The balance sheet reflected a total liability related to reclamation of $27 million as of March 31, 2017 and $26 million as of December 31, 2016 . 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 to the coal suppliers. FERC Compliance In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews) and made compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard service agreement form. In 2016, the FERC issued orders related to the late-filed TSAs which directed TEP to issue time-value refunds to the counterparties to these TSAs (FERC Refund Orders). As a result of the FERC Refund Orders and ongoing discussions with the OE, in 2016 TEP recorded $22 million in time-value refunds offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income, and, of the amount accrued, paid out $17 million in time-value refunds to the counterparties. In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. Under the agreement, the counterparty paid TEP $8 million in January 2017, which TEP recorded in Other Income on the Condensed Consolidated Statements of Income, and TEP dismissed the appeal with prejudice. The Condensed Consolidated Balance Sheets reflected $5 million as of March 31, 2017 and December 31, 2016 , accrued in Current Liabilities—Other. TEP's Compliance Reviews are still under review by the OE. The FERC could impose civil penalties on TEP as a result of the OE's review of the Compliance Reviews. At this time, TEP cannot predict the outcome or range of additional losses, if any. Performance Guarantees TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and with Luna Generating Station (Luna). The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, the non-defaulting participants have agreed to bear a 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 (undiscounted) 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, 2017 , there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019 , San Juan in 2022, Four Corners in 2041, and Luna in 2046. 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 condensed consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in material compliance with all applicable environmental laws and regulations.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	3 Months Ended
	Mar. 31, 2017
Compensation and Retirement Disclosure [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) 2017 2016 2017 2016 Service Cost $ 3 $ 3 $ 1 $ 1 Interest Cost 4 4 — — Expected Return on Plan Assets (6 ) (6 ) — — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 3 $ 3 $ 1 $ 1

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: Three Months Ended March 31, (in millions) 2017 2016 Accrued Capital Expenditures $ 19 $ 14 Net Cost of Removal (1) 10 3 (1) Non-cash Net Cost of Removal represents an accrual for future AROs that does not impact earnings.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	3 Months Ended
	Mar. 31, 2017
Disclosure Text Block [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. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented. 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. These assets and liabilities are 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, 2017 Assets Cash Equivalents (1) $ 22 $ — $ — $ 22 Restricted Cash (1) 7 — — 7 Energy Derivative Contracts, Regulatory Recovery (2) — 2 1 3 Energy Derivative Contracts, No Regulatory Recovery (2) — — 1 1 Total Assets 29 2 2 33 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (7 ) (1 ) (8 ) Interest Rate Swap (3) — (2 ) — (2 ) Total Liabilities — (9 ) (1 ) (10 ) Total Assets (Liabilities), Net $ 29 $ (7 ) $ 1 $ 23 (in millions) December 31, 2016 Assets Cash Equivalents (1) $ 23 $ — $ — $ 23 Restricted Cash (1) 7 — — 7 Energy Derivative Contracts, Regulatory Recovery (2) — 3 — 3 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 30 3 2 35 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (2 ) (1 ) (3 ) Interest Rate Swap (3) — (2 ) — (2 ) Total Liabilities — (4 ) (1 ) (5 ) Total Assets (Liabilities), Net $ 30 $ (1 ) $ 1 $ 30 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds 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 on the Condensed Consolidated Balance Sheets. (2) Energy 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. The valuation techniques are described below. (3) The Interest Rate Swap is valued using an income valuation approach based on the 6-month London Interbank Offered Rate (LIBOR) and is 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, 2017 Derivative Assets Energy Derivative Contracts $ 4 $ 3 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (8 ) (3 ) — (5 ) Interest Rate Swap (2 ) — — (2 ) (in millions) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) 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. 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 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 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, 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 loss expected to be reclassified to earnings within the next twelve months is estimated to be $1 million . The realized losses from its cash flow hedges are less than $1 million for the three months ended March 31, 2017 and 2016 , respectively. As of March 31, 2017 , the total notional amount of the interest rate swap was $18 million . Energy Derivative Contracts - Regulatory Recovery TEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in the statement of other comprehensive income, as shown in the following table: Three Months Ended March 31, (in millions) 2017 2016 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (5 ) $ (2 ) Energy Derivative Contracts - No Regulatory Recovery Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For contracts that qualify as derivatives, TEP records unrealized gains and losses in the income statement unless, and until, a normal purchase or normal sale election is made. The unrealized gains and losses on long-term power trading contracts are recorded in the income statement, and 10% of any gains will be shared with ratepayers through the PPFAC, as realized. Derivative Volumes As of March 31, 2017 , TEP had energy contracts that will settle through 2020 . The volumes associated with the energy contracts were as follows: March 31, 2017 December 31, 2016 Power Contracts GWh 1,846 2,610 Gas Contracts BBtu 21,832 12,355 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 Range of Unobservable Input Assets Liabilities Unobservable Inputs (in millions) March 31, 2017 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 12.15 $ 36.80 (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 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: Three Months Ended March 31, (in millions) 2017 2016 Beginning of Period $ 1 $ (2 ) Gains (Losses) Recorded (1) Regulatory Assets or Liabilities, Derivative Instruments 1 (1 ) Settlements (1 ) — End of Period $ 1 $ (3 ) (1) Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $1 million and $(1) million for the three months ended March 31, 2017 and 2016 , respectively. 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 measurement 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, a Letter of Credit (LOC), 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 collateral posted, and then allocates the credit risk adjustment to all individual contracts. Material adverse changes could trigger credit risk-related contingent features. 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 $12 million as of March 31, 2017 , compared with $8 million as of December 31, 2016 . As of March 31, 2017 , TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on March 31, 2017 , TEP would have been required to post an additional $12 million of collateral of which $7 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. TEP uses the following methods and assumptions for estimating the fair value of financial instruments: • Borrowings under revolving credit facilities approximate the fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below. • For long-term debt, TEP uses quoted market prices, when available, or calculates the present value of remaining cash flows at the balance sheet date. When calculating present value, the Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. The Company also incorporates the impact of its own credit risk using a credit default swap rate. 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, 2017 December 31, 2016 March 31, 2017 December 31, 2016 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,490 $ 1,472

RECENTLY ISSUED ACCOUNTING PRON

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2017
Disclosure Text Block [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS TEP considers the applicability and impact of all accounting standard updates issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and either determined to not be applicable or are expected to have minimal impact on TEP's condensed consolidated financial position, results of operations, or disclosures. REVENUE FROM CONTRACTS WITH CUSTOMERS In May 2014, the FASB issued an accounting standard update that will eliminate the transaction and industry-specific revenue recognition guidance under current GAAP and replace it with a principles-based approach for determining revenue recognition. In July 2015, the FASB voted to defer the effective date of the revenue recognition standard by one year, and TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2018. The Company has elected not to early adopt this standard. The revenue standard requires entities to apply the guidance retrospectively or under the modified retrospective approach by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. TEP expects to use the modified retrospective approach. Retail and wholesale sales of energy based on regulator-approved tariff rates represent TEP’s primary sources of revenue. TEP does not expect that the adoption of this standard will have a material impact on the recognition of revenue from energy sales to retail or wholesale customers. Certain industry specific interpretative issues, including contributions in aid of construction, remain outstanding. The conclusions reached, if different than currently anticipated, could change the Company's expected method of adoption and have a material impact on the Company’s consolidated financial statements and related disclosures. LEASES In February 2016, the FASB issued an accounting standard update that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under current GAAP. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures. RESTRICTED CASH In November 2016, the FASB issued an accounting standard update that will require entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. The standard is effective for annual and interim periods beginning January 1, 2018, and is to be applied using a retrospective approach. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures. COMPENSATION—RETIREMENT BENEFITS In March 2017, the FASB issued an accounting standard update to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendments in this update require that an employer disaggregate the service cost component from the other components of net periodic benefit cost. The guidance on the presentation of the components of net periodic benefit cost in the income statement will be applied retrospectively. The amendments also allow only the service cost component of net periodic benefit cost to be eligible for capitalization prospectively. The standard is effective for annual and interim periods beginning January 1, 2018. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures.

NATURE OF OPERATIONS AND FINA19

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 2017
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 Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) 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's proportionate share of jointly owned facilities is recorded in Utility Plant on the Condensed Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included 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 its 2016 Annual Report on Form 10-K. The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation 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.
Reclassification	Certain amounts from prior periods have been reclassified to conform to the current period presentation. TEP's income statement reflects a reclassification related to wholesale contracts. The Condensed Consolidated Income Statements reflect a reclassification between Wholesale Revenues and Purchased Power Expense of $2 million for the three months ended March 31, 2016 . Management does not believe the reclassification is material to the previously issued financial statements.
Variable Interest Entity	Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (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 Purchased Power Agreements (PPA) 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 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, 2017 , 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 retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
Recently Adopted Accounting Pronouncements	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS Effective January 1, 2016, TEP adopted accounting guidance that simplifies the accounting for share-based payment accounting. The guidance requires that excess tax benefits and tax deficiencies be recorded as an income tax benefit or expense on the statement of income and eliminates the requirement that excess tax benefits be realized before companies can recognize them. On adoption, using the modified retrospective method of transition, TEP recorded a cumulative effect adjustment of $10 million to increase retained earnings and decrease deferred income taxes related to prior period unrecognized excess tax benefits. The impact on the income statement and the statement of cash flows were not significant. TEP elected to recognize forfeitures when they occur. Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principle is not expected to have any impact on TEP as the Company recovers the cost of inventory in rates.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	3 Months Ended
	Mar. 31, 2017
Regulated Operations [Abstract]
Schedule of Purchased Power and Fuel Adjustment Rates	The table below presents TEP's PPFAC rates approved by the ACC: Period Cents per kWh March 2017 through March 2018 (0.20 ) May 2016 through February 2017 0.15 April 2015 through April 2016 0.68
Schedule of Regulatory Assets and Liabilities	The regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: (dollars in millions) Remaining Recovery Period (years) March 31, 2017 December 31, 2016 Regulatory Assets Pension and Other Postretirement Benefits (Note 7) Various $ 126 $ 128 Final Mine Reclamation and Retiree Health Care Costs (1) 20 29 27 Income Taxes Recoverable through Future Rates Various 29 29 Lost Fixed Cost Recovery 1 27 23 Property Tax Deferrals 1 23 23 Springerville Unit 1 Leasehold Improvements (2) 6 15 17 Sundt Coal Handling Facilities (3) N/A — 14 Other Regulatory Assets Various 32 20 Total Regulatory Assets 281 281 Less Current Portion 1 60 56 Total Non-Current Regulatory Assets $ 221 $ 225 Regulatory Liabilities Net Cost of Removal for Interim Retirements (4) Various $ 280 $ 270 Renewable Energy Standard Various 34 32 Purchased Power and Fuel Adjustment Clause 1 31 38 Deferred Investment Tax Credits Various 23 23 Other Regulatory Liabilities Various 10 14 Total Regulatory Liabilities 378 377 Less Current Portion 1 69 76 Total Non-Current Regulatory Liabilities $ 309 $ 301 (1) Final Mine Reclamation and Retiree Health Care Costs represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and Navajo Generating Station (Navajo). TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037 . (2) Springerville Unit 1 Leasehold Improvements represent 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 amortization period. (3) In March 2016, TEP notified the Environmental Protection Agency (EPA) of its decision to permanently eliminate coal as a fuel source, and transferred the net book value (NBV) of the Sundt Coal Handling Facilities to a regulatory asset. The ACC authorized TEP to apply excess depreciation reserves against the unrecovered NBV in the 2017 Rate Order. As a result, TEP transferred $14 million from Regulatory Assets to Accumulated Depreciation on the Condensed Consolidated Balance Sheets. (4) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	3 Months Ended
	Mar. 31, 2017
Accounts Receivable, Net [Abstract]
Accounts Receivable	The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2017 December 31, 2016 Customer $ 66 $ 74 Due from Affiliates (Note 4) 5 9 Unbilled 30 34 Other 13 13 Allowance for Doubtful Accounts (5 ) (5 ) Accounts Receivable, Net $ 109 $ 125

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Table)	3 Months Ended
	Mar. 31, 2017
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, 2017 December 31, 2016 Receivables from Related Parties UNS Electric $ 4 $ 7 UNS Gas 1 2 Total Due from Related Parties $ 5 $ 9 Payables to Related Parties SES $ 2 $ 2 UNS Energy 1 — Total Due to Related Parties $ 3 $ 2 The following table presents the related party transactions included in the income statement: Three Months Ended March 31, (in millions) 2017 2016 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 1 $ 1 Control Area Services, UNS Electric (2) 1 — Common Costs, UNS Energy Affiliates (3) 4 3 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 3 4 Corporate Services, UNS Energy (5) 1 2 Corporate Services, UNS Energy Affiliates (6) 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 are 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 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis management fees. For the three months ended March 31, 2017 and 2016 , these costs included Fortis management fees of $1 million . (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.

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2017
Compensation and Retirement Disclosure [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) 2017 2016 2017 2016 Service Cost $ 3 $ 3 $ 1 $ 1 Interest Cost 4 4 — — Expected Return on Plan Assets (6 ) (6 ) — — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 3 $ 3 $ 1 $ 1

SUPPLEMENTAL CASH FLOW INFORM24

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: Three Months Ended March 31, (in millions) 2017 2016 Accrued Capital Expenditures $ 19 $ 14 Net Cost of Removal (1) 10 3 (1) Non-cash Net Cost of Removal represents an accrual for future AROs that does not impact earnings.

FAIR VALUE MEASUREMENTS AND D25

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2017
Disclosure Text Block [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. These assets and liabilities are 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, 2017 Assets Cash Equivalents (1) $ 22 $ — $ — $ 22 Restricted Cash (1) 7 — — 7 Energy Derivative Contracts, Regulatory Recovery (2) — 2 1 3 Energy Derivative Contracts, No Regulatory Recovery (2) — — 1 1 Total Assets 29 2 2 33 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (7 ) (1 ) (8 ) Interest Rate Swap (3) — (2 ) — (2 ) Total Liabilities — (9 ) (1 ) (10 ) Total Assets (Liabilities), Net $ 29 $ (7 ) $ 1 $ 23 (in millions) December 31, 2016 Assets Cash Equivalents (1) $ 23 $ — $ — $ 23 Restricted Cash (1) 7 — — 7 Energy Derivative Contracts, Regulatory Recovery (2) — 3 — 3 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 30 3 2 35 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (2 ) (1 ) (3 ) Interest Rate Swap (3) — (2 ) — (2 ) Total Liabilities — (4 ) (1 ) (5 ) Total Assets (Liabilities), Net $ 30 $ (1 ) $ 1 $ 30 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds 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 on the Condensed Consolidated Balance Sheets. (2) Energy 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. The valuation techniques are described below. (3) The Interest Rate Swap is valued using an income valuation approach based on the 6-month London Interbank Offered Rate (LIBOR) and is 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, 2017 Derivative Assets Energy Derivative Contracts $ 4 $ 3 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (8 ) (3 ) — (5 ) Interest Rate Swap (2 ) — — (2 ) (in millions) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 )
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, 2017 Derivative Assets Energy Derivative Contracts $ 4 $ 3 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (8 ) (3 ) — (5 ) Interest Rate Swap (2 ) — — (2 ) (in millions) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 )
Financial Impact of Energy Contracts	Energy Derivative Contracts - Regulatory Recovery TEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in the statement of other comprehensive income, as shown in the following table: Three Months Ended March 31, (in millions) 2017 2016 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (5 ) $ (2 )
Derivative Volumes	Derivative Volumes As of March 31, 2017 , TEP had energy contracts that will settle through 2020 . The volumes associated with the energy contracts were as follows: March 31, 2017 December 31, 2016 Power Contracts GWh 1,846 2,610 Gas Contracts BBtu 21,832 12,355
Fair Value Inputs, Liabilities, 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 Range of Unobservable Input Assets Liabilities Unobservable Inputs (in millions) March 31, 2017 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 12.15 $ 36.80 (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00
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 Range of Unobservable Input Assets Liabilities Unobservable Inputs (in millions) March 31, 2017 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 12.15 $ 36.80 (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00
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: Three Months Ended March 31, (in millions) 2017 2016 Beginning of Period $ 1 $ (2 ) Gains (Losses) Recorded (1) Regulatory Assets or Liabilities, Derivative Instruments 1 (1 ) Settlements (1 ) — End of Period $ 1 $ (3 ) (1) Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $1 million and $(1) million for the three months ended March 31, 2017 and 2016 , respectively.
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, 2017 December 31, 2016 March 31, 2017 December 31, 2016 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,490 $ 1,472

NATURE OF OPERATIONS AND FINA26

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands	3 Months Ended
	Mar. 31, 2017mi²customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Retail Customers | customer	422
Area In Which Company Generates Transmits And Distributes Electricity To Retail Electric Customers [square mile] | mi²	1,155

NATURE OF OPERATIONS AND FINA27

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Prior Periods Reclassification) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Wholesale Revenue [Member]
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Prior Period Reclassification Adjustment	$ (2)
Purchased Power [Member]
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Prior Period Reclassification Adjustment	$ 2

NATURE OF OPERATIONS AND FINA28

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Recently Adopted Accounting Pronouncements) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Jan. 01, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect adjustment	$ 9,653
Retained Earnings [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect adjustment	$ 9,653
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-09 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred tax liabilities, net		$ 10,000
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-09 [Member] | Retained Earnings [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect adjustment		$ 10,000

REGULATORY MATTERS (2017 Rate O

REGULATORY MATTERS (2017 Rate Order) (Details) - Arizona Corporation Commission [Member] - USD ($) $ in Millions	1 Months Ended
	Feb. 28, 2017	Sep. 30, 2016
Public Utilities, General Disclosures [Line Items]
Approved Return on Original Cost Rate Base, Percentage	7.04%
Approved Cost of Equity, Percentage	9.75%
Approved Cost of Debt Component, Percentage	4.32%
Non-fuel Component of Base Rate [Member]
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase	$ 81.5
Springerville Unit One [Member]
Public Utilities, General Disclosures [Line Items]
Purchased undivided interest in Springerville Unit 1		50.50%
Springerville Unit One [Member] | Non-fuel Component of Base Rate [Member]
Public Utilities, General Disclosures [Line Items]
Unit 1 Operating costs included in base rate increase	$ 15

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details)	1 Months Ended		3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)	Feb. 29, 2016USD ($)	Mar. 31, 2017USD ($)$ / kWh	Mar. 31, 2016USD ($)	Dec. 31, 2025	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified			12 months
Months of preceding period for true up component			12 months
Over-Recovered Costs for Purchased Power and Fuel	$ 31,000,000		$ 31,000,000				$ 38,000,000
Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage							6.00%
Approved Spending Budget	54,000,000
Approved Carryover of Unused Funds	2,000,000
Approved Recovery of Spending Budget	52,000,000
Renewable Energy Actual Percentage							10.00%
Renewable Energy Program [Member] | Scenario, Forecast [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage					15.00%
Distributed Generation Requirement Percent of Target Percentage					30.00%
Recovery Revenue						$ 1,000,000
Demand Side Management - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue			2,000,000	$ 2,000,000
Requested Rate Increase to Demand Side Management Surcharge, Amount	$ 7,000,000
Over-Collected Costs for Approved Energy Efficiency Programs		$ 8,000,000
Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Approved Spending Budget		22,000,000
Approved Recovery of Spending Budget		$ 14,000,000
Lost Fixed Cost Recovery Mechanism - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue			$ 6,000,000	$ 5,000,000
Cap on Increase in Lost Fixed Cost Recovery Rate			2.00%
Effective March 2017 through March 2018 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh			(0.0020)
Effective May 2016 Through February 2017 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh			0.0015
Effective April 2015 through April 2016 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh			0.0068

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Assets	$ 281,000	$ 281,000
Regulatory Assets, Current	59,530	56,340
Regulatory Assets, Noncurrent	220,827	225,453
Pension and Other Postretirement Benefits (Note 7)
Regulatory Assets [Line Items]
Regulatory Assets	$ 126,000	128,000
Final Mine Reclamation and Retiree Health Care Costs (1)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	20 years
Regulatory Assets	$ 29,000	27,000
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Regulatory Assets	$ 29,000	29,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Assets	$ 27,000	23,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Assets	$ 23,000	23,000
Springerville Unit 1 Leasehold Improvements (2)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	6 years
Regulatory Assets	$ 15,000	17,000
Amortization period authorized to recover leasehold improvement costs at Springerville Unit 1	10 years
Sundt Coal Handling Facilities (3)
Regulatory Assets [Line Items]
Regulatory Assets	$ 0	14,000
Net Book Value of Coal Handling Facilities Transferred from Regulatory Assets to Accumulated Depreciation	14,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Assets	$ 32,000	$ 20,000

REGULATORY MATTERS (Regulator32

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Liabilities	$ 378,000	$ 377,000
Regulatory Liabilities, Current	69,199	76,069
Regulatory Liabilities, Noncurrent	308,825	300,700
Net Cost of Removal for Interim Retirements (4)
Regulatory Liabilities [Line Items]
Regulatory Liabilities	280,000	270,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 34,000	32,000
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Liabilities	$ 31,000	38,000
Deferred Investment Tax Credits
Regulatory Liabilities [Line Items]
Regulatory Liabilities	23,000	23,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 10,000	$ 14,000

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts	$ (5,000)	$ (5,000)
Accounts Receivable, Net	108,889	124,934
Customer
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	66,000	74,000
Customer | Unbilled
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	30,000	34,000
Customer | Due from Affiliates (Note 4)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	5,000	9,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	$ 13,000	$ 13,000

RELATED PARTY TRANSACTIONS (Rec

RELATED PARTY TRANSACTIONS (Receivables From/To and Goods and Services Provided By/To) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Receivable—Due from Related Parties	$ 5		$ 9
Accounts Payable—Due to Related Parties	3		2
Transmission Revenues To UNS Electric [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Transmission Revenues	1	$ 1
Tucson Electric Power Company To UNS Electric [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Control Area Services	1	0
Common Costs Provided to UNS Energy Affiliates [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Common Costs	4	3
Supplemental Workforce provided to TEP from SES [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Supplemental Workforce	3	4
Corporate Services - UNS Energy to TEP [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate Services	1	2
Management fee	1	1
UNS Energy Affiliates to TEP [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate Services	1	$ 0
UNS Electric [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Receivable—Due from Related Parties	4		7
UNS Gas [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Receivable—Due from Related Parties	1		2
SES [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Payable—Due to Related Parties	2		2
UNS Energy [Member]
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Payable—Due to Related Parties	$ 1		$ 0
Massachusetts Formula - TEP's allocation percentage	82.00%

RELATED PARTY TRANSACTIONS (Con

RELATED PARTY TRANSACTIONS (Contribution From and Dividend Declared and Paid To Parent) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Related Party Transactions [Abstract]
Equity Contributions from UNS Energy	$ 0	$ 0
Dividends Declared to UNS Energy	0	0
Dividends Paid to UNS Energy	$ 0	$ 0

DEBT, CREDIT FACILITY, AND CA36

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Details) - Revolving Credit Facility [Member] - Line of Credit [Member] - USD ($) $ in Millions	May 01, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		$ 250
Subsequent Event [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 235

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
FERC Refund Orders [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual, Payments			$ 17
FERC Refund Orders [Member] | Wholesale Revenue [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual, Provision			22
FERC Refund Orders [Member] | Other Income [Member] | Settled Litigation [Member]
Commitments And Contingencies [Line Items]
Litigation Settlement Amount	$ 8
Other Current Liabilities [Member] | FERC Refund Orders [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual		$ 5	5
Navajo, San Juan, Four Corners [Member]
Commitments And Contingencies [Line Items]
Share of Reclamation Costs Anticipated		61
Navajo, San Juan, Four Corners [Member] | Other Liabilities [Member]
Commitments And Contingencies [Line Items]
Environmental Exit Costs, Costs Accrued to Date		$ 27	$ 26

COMMITMENTS AND CONTINGENCIES C

COMMITMENTS AND CONTINGENCIES COMMITMENTS AND CONTINGENCIES (PERFORMANCE GUARANTEES) (Details) - Performance Guarantee [Member]	Mar. 31, 2017USD ($)
Guarantor Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	$ 0
Four Corner [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	250,000,000
Navajo, San Juan, Luna [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 0

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pension Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 3	$ 3
Interest Cost	4	4
Expected Return on Plan Assets	(6)	(6)
Amortization of Net Loss	2	2
Net Periodic Benefit Cost	3	3
Other Postretirement Benefits [Member]
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

SUPPLEMENTAL CASH FLOW INFORM40

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Other Noncash Investing and Financing Items [Abstract]
Accrued Capital Expenditures	$ 19	$ 14
Net Cost of Removal	$ 10	$ 3

FAIR VALUE MEASUREMENTS AND D41

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Net Fair Value Measurements, Recurring [Member] - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Assets
Cash Equivalents	$ 22	$ 23
Restricted Cash	7	7
Energy Derivative Contract Assets - Regulatory Recovery	3	3
Energy Derivative Contract Assets - No Regulatory Recovery	1	2
Total Assets	33	35
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(8)	(3)
Interest Rate Swap	(2)	(2)
Total Liabilities	(10)	(5)
Net Total Assets (Liabilities)	23	30
Level 1 [Member]
Assets
Cash Equivalents	22	23
Restricted Cash	7	7
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	29	30
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Interest Rate Swap	0	0
Total Liabilities	0	0
Net Total Assets (Liabilities)	29	30
Level 2 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	2	3
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	2	3
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(7)	(2)
Interest Rate Swap	(2)	(2)
Total Liabilities	(9)	(4)
Net Total Assets (Liabilities)	(7)	(1)
Level 3 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	1	0
Energy Derivative Contract Assets - No Regulatory Recovery	1	2
Total Assets	2	2
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(1)	(1)
Interest Rate Swap	0	0
Total Liabilities	(1)	(1)
Net Total Assets (Liabilities)	$ 1	$ 1

FAIR VALUE MEASUREMENTS AND D42

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Energy Related Derivative [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Asset, Gross Amount Recognized in the Balance Sheets	$ 4	$ 5
Derivative Asset, Counterparty Netting of Energy Contracts	3	2
Cash Collateral Received	0	0
Derivative Asset, Net Amount	1	3
Derivative Liability, Gross Amount Recognized in the Balance Sheets	(8)	(3)
Derivative Liability, Counterparty Netting of Energy Contracts	(3)	(2)
Cash Collateral Posted	0	0
Derivative (Liability), Net Amount	(5)	(1)
Interest Rate Swap [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Liability, Gross Amount Recognized in the Balance Sheets	(2)	(2)
Derivative Liability, Counterparty Netting of Energy Contracts	0	0
Cash Collateral Posted	0	0
Derivative (Liability), Net Amount	$ (2)	$ (2)

FAIR VALUE MEASUREMENTS AND D43

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Derivative [Line Items]
Cash Flow Hedge Loss to be Reclassified within Twelve Months	$ 1

FAIR VALUE MEASUREMENTS AND D44

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Realized Losses From Cash Flow Hedges [Line Items]
Realized losses from cash flow hedges are less than	$ 664,000	$ 858,000
Interest Rate Swap [Member]
Realized Losses From Cash Flow Hedges [Line Items]
Realized losses from cash flow hedges are less than	$ 1,000,000	$ 1,000,000

FAIR VALUE MEASUREMENTS AND D45

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Percent of long-term trading contract gains shared with ratepayers	10.00%
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$ (5)	$ (2)

FAIR VALUE MEASUREMENTS AND D46

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) $ in Millions	Mar. 31, 2017USD ($)GWhBTU	Dec. 31, 2016GWhBTU
Interest Rate Swap [Member]
Derivative Volume [Line Items]
Derivative Liability, Notional Amount | $	$ 18
Power Contracts (in GWh) [Member]
Derivative Volume [Line Items]
Derivatives Volumes | GWh	1,846	2,610
Gas Contracts (in Btu) [Member]
Derivative Volume [Line Items]
Derivatives Volumes | BTU	21,832,000,000,000	12,355,000,000,000

FAIR VALUE MEASUREMENTS AND D47

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 [Member] - Market Approach Valuation Technique [Member] - Forward Contracts [Member] $ in Millions	Mar. 31, 2017USD ($)$ / megawatt_hour	Dec. 31, 2016USD ($)$ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets | $	$ 2	$ 2
Derivative Liabilities | $	$ (1)	$ (1)
Minimum [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh | $ / megawatt_hour	12.15	20.90
Maximum [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh | $ / megawatt_hour	36.80	40

FAIR VALUE MEASUREMENTS AND D48

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning of Period	$ 1,000,000	$ (2,000,000)
Changes in the fair value of assets and liabilities classified as Level 3
Gains (Losses) Recorded to Regulatory Assets or Liabilities, Derivative Instruments	1,000,000	(1,000,000)
Settlements	(1,000,000)	0
End of Period	1,000,000	(3,000,000)
Gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held	1,000,000	(1,000,000)
Transfers out of Level 3	$ 0	$ 0

FAIR VALUE MEASUREMENTS AND D49

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale	$ 12,000,000	$ 8,000,000
Additional collateral required to post if credit-risk contingent features are triggered	12,000,000
Amount relating to outstanding net payable balances for settled positions [Member]
Derivative [Line Items]
Additional collateral required to post if credit-risk contingent features are triggered	7,000,000
Line of Credit Collateral [Member]
Derivative [Line Items]
LOCs as credit enhancements with counterparties	$ 0

FAIR VALUE MEASUREMENTS AND D50

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Including Current Maturities, Face Value	$ 1,466	$ 1,466
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities, Fair Value	$ 1,490	$ 1,472