Tucson Electric Power 10-Q 3 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 02, 2017
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
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 Common Stock, Shares Outstanding		32,139,434

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues
Retail	$ 340,410	$ 320,379	$ 820,453	$ 780,782
Wholesale	43,868	32,151	130,242	80,648
Other	32,932	41,605	87,041	93,668
Total Operating Revenues	417,210	394,135	1,037,736	955,098
Operating Expenses
Fuel	91,754	86,530	218,226	217,444
Purchased Power	38,903	30,031	107,039	71,794
Transmission and Other PPFAC Recoverable Costs	10,285	7,143	27,167	17,633
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(9,166)	5,091	(24,773)	19,356
Total Fuel and Purchased Power	131,776	128,795	327,659	326,227
Operations and Maintenance	89,862	88,699	256,493	260,278
Depreciation	38,302	36,565	114,667	108,110
Amortization	5,463	5,558	16,323	16,579
Taxes Other Than Income Taxes	13,549	12,646	40,329	38,376
Total Operating Expenses	278,952	272,263	755,471	749,570
Operating Income	138,258	121,872	282,265	205,528
Other Income (Deductions)
Interest Income	30	11	556	78
Other Income	1,738	1,774	12,630	4,427
Other Expense	(1,072)	(1,166)	(2,609)	(2,052)
Appreciation in Value of Investments	912	722	2,130	1,582
Total Other Income (Deductions)	1,608	1,341	12,707	4,035
Interest Expense
Long-Term Debt	15,531	15,545	46,461	46,522
Capital Leases	613	821	1,941	2,534
Other Interest Expense	147	114	570	372
Interest Capitalized	(525)	(436)	(1,645)	(1,297)
Total Interest Expense	15,766	16,044	47,327	48,131
Income Before Income Taxes	124,100	107,169	247,645	161,432
Income Tax Expense	42,100	35,556	83,951	49,985
Net Income	$ 82,000	$ 71,613	$ 163,694	$ 111,447

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net Income	$ 82,000	$ 71,613	$ 163,694	$ 111,447
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges: Net of Income Tax Expense	121	247	336	385
Supplemental Executive Retirement Plan Adjustments: Net of income Tax Expense of $43 and $35	69	55	209	168
Total Other Comprehensive Income, Net of Tax	190	302	545	553
Total Comprehensive Income	$ 82,190	$ 71,915	$ 164,239	$ 112,000

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Tax Expense related to Change in Fair Value of Cash Flow Hedges	$ 79	$ 155	$ 212	$ 242
Tax Expense related to Supplemental Executive Retirement Plan Adjustments	$ 44	$ 34	$ 130	$ 104

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Statement of Cash Flows [Abstract]
Net Income	$ 163,694	$ 111,447
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	114,667	108,110
Amortization Expense	16,323	16,579
Amortization of Debt Issuance Costs	1,763	2,176
Use of Renewable Energy Credits for Compliance	17,434	13,048
Deferred Income Taxes	83,954	49,972
Pension and Other Postretirement Benefits Expense	12,029	11,504
Pension and Other Postretirement Benefits Funding	(12,763)	(12,672)
Allowance for Equity Funds Used During Construction	(4,145)	(3,410)
FERC Transmission Refund Payable	(4,878)	18,783
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(59,016)	(24,743)
Materials, Supplies, and Fuel Inventory	452	8,366
Regulatory Assets	(2,407)	(7,533)
Accounts Payable and Accrued Charges	25,628	23,139
Regulatory Liabilities	(10,258)	21,648
Other, Net	(5,213)	5,033
Net Cash Flows—Operating Activities	337,264	341,447
Cash Flows from Investing Activities
Capital Expenditures	(215,826)	(187,678)
Purchase, Springerville Unit 1 Assets	0	(85,000)
Purchase Intangibles, Renewable Energy Credits	(40,838)	(31,192)
Contributions in Aid of Construction	3,265	1,965
Other, Net	(975)	0
Net Cash Flows—Investing Activities	(254,374)	(301,905)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facilities	35,000	0
Repayments of Borrowings, Revolving Credit Facilities	(35,000)	0
Dividend Paid to Parent	(35,000)	(20,000)
Payments of Capital Lease Obligations	(14,804)	(14,080)
Other, Net	641	(4,107)
Net Cash Flows—Financing Activities	(49,163)	(38,187)
Net Increase in Cash and Cash Equivalents	33,727	1,355
Cash and Cash Equivalents, Beginning of Period	35,962	55,684
Cash and Cash Equivalents, End of Period	$ 69,689	$ 57,039

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Utility Plant
Plant in Service	$ 5,633,029	$ 5,975,139
Utility Plant Under Capital Leases	167,413	167,413
Construction Work in Progress	165,139	129,955
Total Utility Plant	5,965,581	6,272,507
Accumulated Depreciation and Amortization	(2,153,176)	(2,385,053)
Accumulated Amortization of Capital Lease Assets	(109,743)	(104,648)
Total Utility Plant, Net	3,702,662	3,782,806
Investments and Other Property	47,099	45,020
Current Assets
Cash and Cash Equivalents	69,689	35,962
Accounts Receivable, Net	186,007	124,934
Fuel Inventory	23,943	25,887
Materials and Supplies	103,435	97,126
Regulatory Assets	66,899	56,340
Derivative Instruments	4,912	4,966
Other	14,713	13,793
Total Current Assets	469,598	359,008
Regulatory and Other Assets
Regulatory Assets	299,943	225,453
Derivative Instruments	549	330
Other	55,321	37,372
Total Regulatory and Other Assets	355,813	263,155
Total Assets	4,575,172	4,449,989
Capitalization
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2017, and December 31, 2016)	1,296,539	1,296,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	402,102	273,408
Accumulated Other Comprehensive Loss	(4,010)	(4,555)
Total Common Stock Equity	1,688,274	1,559,035
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2017, and December 31, 2016)	0	0
Capital Lease Obligations	28,518	39,267
Long-Term Debt, Net	1,454,085	1,453,072
Total Capitalization	3,170,877	3,051,374
Current Liabilities
Capital Lease Obligations	47,224	51,765
Accounts Payable	95,353	89,797
Accrued Taxes Other than Income Taxes	60,167	37,639
Accrued Employee Expenses	25,034	29,465
Accrued Interest	13,135	14,508
Regulatory Liabilities	66,066	76,069
Customer Deposits	24,676	25,778
Derivative Instruments	4,579	2,641
Other	10,830	17,837
Total Current Liabilities	347,064	345,499
Regulatory and Other Liabilities
Deferred Income Taxes, Net	619,838	529,148
Regulatory Liabilities	205,546	300,700
Pension and Other Postretirement Benefits	125,762	131,630
Derivative Instruments	5,041	2,629
Other	101,044	89,009
Total Regulatory and Other Liabilities	1,057,231	1,053,116
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 4,575,172	$ 4,449,989

CONDENSED CONSOLIDATED BALANCE7

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (Unaudited) - $ / shares	Sep. 30, 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	Capital Stock Expense	Retained Earnings	Accumulated Other Comprehensive Loss
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	111,447			111,447
Other Comprehensive Income, Net of Tax	553				553
Dividend Declared to Parent	(20,000)			(20,000)
Balances at Sep. 30, 2016	1,576,588	1,296,539	(6,357)	290,417	(4,011)
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	163,694			163,694
Other Comprehensive Income, Net of Tax	545
Dividend Declared to Parent	(35,000)			(35,000)
Balances at Sep. 30, 2017	$ 1,688,274	$ 1,296,539	$ (6,357)	$ 402,102	$ (4,010)

NATURE OF OPERATIONS AND FINANC

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	9 Months Ended
	Sep. 30, 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 Operating Expenses 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 TEP's 2016 Annual Report on Form 10-K. The condensed consolidated financial statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair 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. 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 Power Purchase 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 September 30, 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 income statement 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 and the cash flow statements was 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 did not have any impact on TEP as the Company recovers the cost of inventory through its rates. UTILITY PLANT Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction, less contributions in aid of construction. Retirements In March 2017, TEP recorded the early retirement of Unit 2 of the San Juan Generating Station (San Juan) and the coal handling facilities at H. Wilson Sundt Generating Station (Sundt) in accordance with provisions in a rate order issued by the Arizona Corporation Commission (ACC) that took effect February 27, 2017 (2017 Rate Order). The Condensed Consolidated Balance Sheets reflect a: (i) $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2; and (ii) $14 million decrease in Regulatory Assets and Accumulated Depreciation and Amortization related to the coal handling facilities at Sundt. See Note 2 for additional information related to the 2017 Rate Order. In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo Generating Station (Navajo) to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's net book value (NBV) and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets as of September 30, 2017. See Note 2 for additional information related to the planned early retirement of Navajo. In August 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of reciprocating internal combustion engines (RICE) in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to the planned early retirement of Sundt Units 1 and 2. Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). In the 2017 Rate Order, the ACC approved the results of a new depreciation study for TEP. In May 2017, TEP transferred $87 million from Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of the revised depreciation study on the estimated cost of removal. See Note 2 for additional information related to the net cost of removal balance in Regulatory Liabilities.

REGULATORY MATTERS

REGULATORY MATTERS	9 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS The ACC and the FERC each regulate portions of utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales. 2017 RATE ORDER In February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017. 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% ; • adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and • approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement. 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 (Phase 2), which is currently expected to be completed in the first quarter of 2018. 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 recovery of 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 $20 million as of September 30, 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 with a budget of $54 million , which was partially offset by applying $2 million of previously recovered carryover funds. TEP will 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; and (iii) various other program costs. 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 RES in 2016 was 11% , which exceeded the overall 2016 RES 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 regulated utilities a DSM surcharge to recover the costs to implement DSM programs from retail customers, 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 both 2017 and 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 with a budget of approximately $22 million , which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customers through the DSM surcharge. 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. In June 2016, TEP notified the ACC that it would not file a 2017 energy efficiency implementation plan and instead continue the 2016 level of recovery through the end of 2017. TEP plans to reduce its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017. TEP filed its 2018 energy efficiency implementation plan in August 2017 and requested the Commission issue an order prior to the end of 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 customer installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of 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, as approved in the 2017 Rate Order. TEP recorded regulatory assets and recognized LFCR revenues of $6 million and $17 million in the three and nine months ended September 30, 2017 , respectively, and $5 million and $14 million in the three and nine months ended September 30, 2016 , respectively. LFCR revenues are included in Retail Revenues on the Condensed Consolidated Statements of Income. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: (dollars in millions) Remaining Recovery Period (years) September 30, 2017 December 31, 2016 Regulatory Assets Pension and Other Postretirement Benefits (Note 7) Various $ 123 $ 128 Early Generation Retirement Costs (1) Various 83 — Final Mine Reclamation and Retiree Health Care Costs (2) 20 34 27 Income Taxes Recoverable through Future Rates Various 31 29 Lost Fixed Cost Recovery 1 29 23 Property Tax Deferrals 1 24 23 Springerville Unit 1 Leasehold Improvements (3) 6 14 17 Sundt Coal Handling Facilities (4) N/A — 14 Other Regulatory Assets Various 29 20 Total Regulatory Assets 367 281 Less Current Portion 1 67 56 Total Non-Current Regulatory Assets $ 300 $ 225 Regulatory Liabilities Net Cost of Removal (5) Various $ 180 $ 270 Renewable Energy Standard Various 43 32 Purchased Power and Fuel Adjustment Clause 1 20 38 Deferred Investment Tax Credits Various 20 23 Other Regulatory Liabilities Various 9 14 Total Regulatory Liabilities 272 377 Less Current Portion 1 66 76 Total Non-Current Regulatory Liabilities $ 206 $ 301 (1) Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. As of September 30, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 1 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2. (2) Includes costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and 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 . (3) Represents investments TEP made 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. (4) The ACC authorized TEP to apply excess depreciation reserves against the unrecovered NBV in the 2017 Rate Order. (5) Net Cost of Removal represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal. Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs, TEP does not pay a return on regulatory liabilities. 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. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 6 for additional information related to FERC compliance associated with these transmission contracts.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	9 Months Ended
	Sep. 30, 2017
Receivables [Abstract]
Accounts Receivable	CCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2017 December 31, 2016 Customer $ 118 $ 74 Due from Affiliates (Note 4) 7 9 Unbilled 49 34 Other 18 13 Allowance for Doubtful Accounts (6 ) (5 ) Accounts Receivable, Net $ 186 $ 125

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 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) September 30, 2017 December 31, 2016 Receivables from Related Parties UNS Electric $ 5 $ 7 UNS Gas 2 2 Total Due from Related Parties $ 7 $ 9 Payables to Related Parties SES $ 2 $ 2 UNS Electric 1 — Total Due to Related Parties $ 3 $ 2 The following table presents the related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 2 $ 2 $ 5 $ 5 Control Area Services, UNS Electric (2) 1 1 2 2 Common Costs, UNS Energy Affiliates (3) 4 3 12 10 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 4 3 11 10 Corporate Services, UNS Energy (5) 1 1 4 5 Corporate Services, UNS Energy Affiliates (6) 1 1 3 3 (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. TEP's share of Fortis' management fees were $1 million and $3 million for the three and nine months ended September 30, 2017 , respectively, and $1 million and $4 million for the three and nine months ended September 30, 2016 , respectively. (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. DIVIDENDS PAID TO PARENT TEP declared and paid a $35 million dividend to UNS Energy in the three and nine months ended September 30, 2017 , and a $20 million dividend to UNS Energy in the three and nine months ended September 30, 2016 .

DEBT, CREDIT FACILITY, AND CAPI

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS	9 Months Ended
	Sep. 30, 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. CREDIT FACILITY TEP's revolving credit facility provides for $250 million of revolving credit commitments with a Letter of Credit (LOC) sublimit of $50 million through its original October 2020 maturity. As permitted by the credit facility, in October 2017 TEP requested and was granted the second of its two one -year extensions effectively extending the final maturity date to October 2022. COVENANT COMPLIANCE As of September 30, 2017 , TEP was in compliance with the terms of its credit and long-term debt agreements.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 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. 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. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice. Claims Related to San Juan Generating Station WildEarth Guardians In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the OSM challenging several unrelated mining plan modification approvals, including two issued in 2008 related to San Juan Coal Company’s (SJCC) San Juan mine. The petition alleges various NEPA violations against the OSM, including failure to provide requisite public notice and participation, and failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the 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 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, but that if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Claims Related to Springerville Generating Station Unit 1 In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the Third-Party Owners’ undivided interest in Springerville Unit 1 for $85 million. As also provided for in the Agreement, TEP received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues—Other on the Consolidated Statements of Income. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice. Mine Reclamation at Generating Facilities Not Operated by TEP TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s 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 $32 million as of September 30, 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, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016. For the three and nine months ended September 30, 2016 , Wholesale Revenues on the Condensed Consolidated Statements of Income reflected $9 million and $22 million , respectively, related to the time-value refunds. As of December 31, 2016 , Current Liabilities—Other on the Condensed Consolidated Balance Sheets reflected $5 million related to the time-value refunds. 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. In accordance with the agreement, the counterparty paid TEP $8 million , which TEP recorded in Other Income on the Condensed Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017. In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Condensed Consolidated Balance Sheets, offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income. 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, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of September 30, 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 applicable environmental laws and regulations.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	9 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2017 2016 2017 2016 Service Cost $ 3 $ 3 $ 1 $ 1 Interest Cost 3 4 1 1 Expected Return on Plan Assets (6 ) (5 ) (1 ) — Amortization of Net Loss 2 1 — — Net Periodic Benefit Cost $ 2 $ 3 $ 1 $ 2 Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Service Cost $ 9 $ 9 $ 3 $ 3 Interest Cost 11 11 2 2 Expected Return on Plan Assets (18 ) (17 ) (1 ) (1 ) Amortization of Net Loss 6 5 — — Net Periodic Benefit Cost $ 8 $ 8 $ 4 $ 4 CONTRIBUTIONS TEP contributed $9 million during the nine months ended September 30, 2017 , to the pension plans. No additional contributions are planned in 2017.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 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: Nine Months Ended September 30, (in millions) 2017 2016 Net Cost of Removal Increase (Decrease) (1) $ (88 ) $ 3 Accrued Capital Expenditures 18 16 Additions to Utility Plant, Springerville Unit 1 Settlement (2) — 5 (1) Non-cash Net Cost of Removal represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information. (2) See Note 6 for additional information regarding the Springerville Unit 1 settlement.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. 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) September 30, 2017 Assets Cash Equivalents (1) $ 59 $ — $ — $ 59 Restricted Cash (1) 8 — — 8 Energy Derivative Contracts, Regulatory Recovery (2) — — 1 1 Energy Derivative Contracts, No Regulatory Recovery (2) — — 4 4 Total Assets 67 — 5 72 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (7 ) — (7 ) Energy Derivative Contracts, No Regulatory Recovery (2) — — (1 ) (1 ) Interest Rate Swap (3) — (1 ) — (1 ) Total Liabilities — (8 ) (1 ) (9 ) Total Assets (Liabilities), Net $ 67 $ (8 ) $ 4 $ 63 (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, insured cash sweep accounts, and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements (Level 2), and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. 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 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) September 30, 2017 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (8 ) (2 ) — (6 ) Interest Rate Swap (1 ) — — (1 ) (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 purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly. Cash Flow Hedges To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020 . The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The 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 shown in the following table: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Capital Lease Interest Expense $ — $ — $ 1 $ 1 As of September 30, 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 September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (1 ) $ 1 $ (6 ) $ 10 Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain contracts that qualify as derivatives, but do not meet the regulatory recovery criteria. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. Derivative Volumes As of September 30, 2017 , TEP had energy contracts that will settle on various expiration dates through 2020 . The volumes associated with the energy contracts were as follows: September 30, 2017 December 31, 2016 Power Contracts GWh 3,840 2,610 Gas Contracts BBtu 29,261 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) September 30, 2017 Forward Power Contracts Market approach $ 5 $ (1 ) Market price per MWh $ 17.55 $ 34.05 (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, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Beginning of Period $ 4 $ 3 $ 1 $ (2 ) Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments 1 1 3 3 Wholesale Revenues — — 4 3 Settlements (1 ) (1 ) (4 ) (1 ) End of Period $ 4 $ 3 $ 4 $ 3 Gains (Losses), Assets (Liabilities) still held $ — $ — $ 4 $ 3 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 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 the collateral posted, and then allocates the credit risk adjustment to the individual contracts. The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $21 million as of September 30, 2017 , compared with $8 million as of December 31, 2016 . As of September 30, 2017 , TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on September 30, 2017 , TEP would have been required to post an additional $21 million of collateral of which $14 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 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 the 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) September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,546 $ 1,472

RECENTLY ISSUED ACCOUNTING PRON

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	9 Months Ended
	Sep. 30, 2017
Accounting Changes and Error Corrections [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS TEP considers the applicability and impact of all Accounting Standard Updates (ASU) 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 a 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 ASU intended to enable users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. Under the new standard, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. TEP does not expect the adoption of this new guidance to affect revenue recognition for tariff-based sales to retail and wholesale customers, which represent TEP's primary source of revenue. Accordingly, TEP does not expect the adoption of this standard to have a material effect on its financial statements. However, the presentation and disclosure requirements of the guidance will result in a change in the presentation of revenues on TEP's consolidated statements of income as well as expanded disclosures. The guidance is effective for annual and interim periods beginning January 1, 2018 and permits two implementation approaches: (i) retrospective application; or (ii) modified retrospective application by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings on the date of adoption supplemented by additional disclosures. TEP plans to adopt this standard on January 1, 2018, using the modified retrospective approach. LEASES In February 2016, the FASB issued an ASU 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 ASU that will require entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents in the cash flow statement. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the cash flow statement. 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 expects to early adopt the new standard effective December 31, 2017. The adoption of the standard will impact the presentation of the cash flow statement but will not have an impact on TEP's financial position or results of operations. COMPENSATION—RETIREMENT BENEFITS In March 2017, the FASB issued an ASU to improve the presentation of net periodic benefit cost for pension and other postretirement benefits. The guidance requires employers to retrospectively present the service cost component in the same line item as other compensation costs and to present the non-service cost components of net periodic benefit costs separately and outside a subtotal of operating income. The ASU is effective for annual and interim periods beginning January 1, 2018. Early adoption is permitted. TEP does not intend to early adopt the ASU and will implement the standard update in the first quarter of 2018. The Company does not expect that its adoption will have a material impact on its financial position or results of operations. DERIVATIVES AND HEDGING In August 2017, the FASB issued an ASU that enables entities to better align their risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance and the presentation of hedge results. The standard update expands an entity's ability to apply hedge accounting to nonfinancial and financial risk components and simplify fair value hedges of interest rate risk. The new guidance eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The amendments to the update also ease hedge documentation and effectiveness assessments requirements under previous guidance. The standard is effective for annual and interim periods beginning January 1, 2019. 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)	9 Months Ended
	Sep. 30, 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 Operating Expenses 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 TEP's 2016 Annual Report on Form 10-K. The condensed consolidated financial statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair 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.
Variable Interest Entities	Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a 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 Power Purchase 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 September 30, 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.
Utility plant	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 income statement 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 and the cash flow statements was 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 did not have any impact on TEP as the Company recovers the cost of inventory through its rates. UTILITY PLANT Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction, less contributions in aid of construction. Retirements In March 2017, TEP recorded the early retirement of Unit 2 of the San Juan Generating Station (San Juan) and the coal handling facilities at H. Wilson Sundt Generating Station (Sundt) in accordance with provisions in a rate order issued by the Arizona Corporation Commission (ACC) that took effect February 27, 2017 (2017 Rate Order). The Condensed Consolidated Balance Sheets reflect a: (i) $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2; and (ii) $14 million decrease in Regulatory Assets and Accumulated Depreciation and Amortization related to the coal handling facilities at Sundt. See Note 2 for additional information related to the 2017 Rate Order. In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo Generating Station (Navajo) to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's net book value (NBV) and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets as of September 30, 2017. See Note 2 for additional information related to the planned early retirement of Navajo. In August 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of reciprocating internal combustion engines (RICE) in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to the planned early retirement of Sundt Units 1 and 2.
Depreciation	Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). In the 2017 Rate Order, the ACC approved the results of a new depreciation study for TEP. In May 2017, TEP transferred $87 million from Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of the revised depreciation study on the estimated cost of removal. See Note 2 for additional information related to the net cost of removal balance in Regulatory Liabilities.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 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	Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: (dollars in millions) Remaining Recovery Period (years) September 30, 2017 December 31, 2016 Regulatory Assets Pension and Other Postretirement Benefits (Note 7) Various $ 123 $ 128 Early Generation Retirement Costs (1) Various 83 — Final Mine Reclamation and Retiree Health Care Costs (2) 20 34 27 Income Taxes Recoverable through Future Rates Various 31 29 Lost Fixed Cost Recovery 1 29 23 Property Tax Deferrals 1 24 23 Springerville Unit 1 Leasehold Improvements (3) 6 14 17 Sundt Coal Handling Facilities (4) N/A — 14 Other Regulatory Assets Various 29 20 Total Regulatory Assets 367 281 Less Current Portion 1 67 56 Total Non-Current Regulatory Assets $ 300 $ 225 Regulatory Liabilities Net Cost of Removal (5) Various $ 180 $ 270 Renewable Energy Standard Various 43 32 Purchased Power and Fuel Adjustment Clause 1 20 38 Deferred Investment Tax Credits Various 20 23 Other Regulatory Liabilities Various 9 14 Total Regulatory Liabilities 272 377 Less Current Portion 1 66 76 Total Non-Current Regulatory Liabilities $ 206 $ 301 (1) Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. As of September 30, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 1 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2. (2) Includes costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and 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 . (3) Represents investments TEP made 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. (4) The ACC authorized TEP to apply excess depreciation reserves against the unrecovered NBV in the 2017 Rate Order. (5) Net Cost of Removal represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal.

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	9 Months Ended
	Sep. 30, 2017
Receivables [Abstract]
Accounts Receivable	The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2017 December 31, 2016 Customer $ 118 $ 74 Due from Affiliates (Note 4) 7 9 Unbilled 49 34 Other 18 13 Allowance for Doubtful Accounts (6 ) (5 ) Accounts Receivable, Net $ 186 $ 125

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	9 Months Ended
	Sep. 30, 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) September 30, 2017 December 31, 2016 Receivables from Related Parties UNS Electric $ 5 $ 7 UNS Gas 2 2 Total Due from Related Parties $ 7 $ 9 Payables to Related Parties SES $ 2 $ 2 UNS Electric 1 — Total Due to Related Parties $ 3 $ 2 The following table presents the related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 2 $ 2 $ 5 $ 5 Control Area Services, UNS Electric (2) 1 1 2 2 Common Costs, UNS Energy Affiliates (3) 4 3 12 10 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 4 3 11 10 Corporate Services, UNS Energy (5) 1 1 4 5 Corporate Services, UNS Energy Affiliates (6) 1 1 3 3 (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. TEP's share of Fortis' management fees were $1 million and $3 million for the three and nine months ended September 30, 2017 , respectively, and $1 million and $4 million for the three and nine months ended September 30, 2016 , respectively. (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)	9 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
Components of Net Periodic Benefit Cost	Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2017 2016 2017 2016 Service Cost $ 3 $ 3 $ 1 $ 1 Interest Cost 3 4 1 1 Expected Return on Plan Assets (6 ) (5 ) (1 ) — Amortization of Net Loss 2 1 — — Net Periodic Benefit Cost $ 2 $ 3 $ 1 $ 2 Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Service Cost $ 9 $ 9 $ 3 $ 3 Interest Cost 11 11 2 2 Expected Return on Plan Assets (18 ) (17 ) (1 ) (1 ) Amortization of Net Loss 6 5 — — Net Periodic Benefit Cost $ 8 $ 8 $ 4 $ 4

SUPPLEMENTAL CASH FLOW INFORM24

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 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: Nine Months Ended September 30, (in millions) 2017 2016 Net Cost of Removal Increase (Decrease) (1) $ (88 ) $ 3 Accrued Capital Expenditures 18 16 Additions to Utility Plant, Springerville Unit 1 Settlement (2) — 5 (1) Non-cash Net Cost of Removal represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information. (2) See Note 6 for additional information regarding the Springerville Unit 1 settlement.

FAIR VALUE MEASUREMENTS AND D25

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Financial Instruments Measured at Fair Value on Recurring Basis	The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis. 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) September 30, 2017 Assets Cash Equivalents (1) $ 59 $ — $ — $ 59 Restricted Cash (1) 8 — — 8 Energy Derivative Contracts, Regulatory Recovery (2) — — 1 1 Energy Derivative Contracts, No Regulatory Recovery (2) — — 4 4 Total Assets 67 — 5 72 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (7 ) — (7 ) Energy Derivative Contracts, No Regulatory Recovery (2) — — (1 ) (1 ) Interest Rate Swap (3) — (1 ) — (1 ) Total Liabilities — (8 ) (1 ) (9 ) Total Assets (Liabilities), Net $ 67 $ (8 ) $ 4 $ 63 (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, insured cash sweep accounts, and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements (Level 2), and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. 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 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) September 30, 2017 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (8 ) (2 ) — (6 ) Interest Rate Swap (1 ) — — (1 ) (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) September 30, 2017 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (8 ) (2 ) — (6 ) Interest Rate Swap (1 ) — — (1 ) (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 )
Realized gain (loss) on cash flow hedges	The realized losses from its cash flow hedges are shown in the following table: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Capital Lease Interest Expense $ — $ — $ 1 $ 1
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 September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (1 ) $ 1 $ (6 ) $ 10
Derivative Volumes	Derivative Volumes As of September 30, 2017 , TEP had energy contracts that will settle on various expiration dates through 2020 . The volumes associated with the energy contracts were as follows: September 30, 2017 December 31, 2016 Power Contracts GWh 3,840 2,610 Gas Contracts BBtu 29,261 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) September 30, 2017 Forward Power Contracts Market approach $ 5 $ (1 ) Market price per MWh $ 17.55 $ 34.05 (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) September 30, 2017 Forward Power Contracts Market approach $ 5 $ (1 ) Market price per MWh $ 17.55 $ 34.05 (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, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Beginning of Period $ 4 $ 3 $ 1 $ (2 ) Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments 1 1 3 3 Wholesale Revenues — — 4 3 Settlements (1 ) (1 ) (4 ) (1 ) End of Period $ 4 $ 3 $ 4 $ 3 Gains (Losses), Assets (Liabilities) still held $ — $ — $ 4 $ 3
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) September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,546 $ 1,472

NATURE OF OPERATIONS AND FINA26

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands	9 Months Ended
	Sep. 30, 2017mi²customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of 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 (Recently Adopted Accounting Pronouncements) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Jan. 01, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect adjustment	$ 9,653
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect adjustment	$ 9,653
New Accounting Pronouncement, Early Adoption, Effect | Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred tax liabilities, net		$ 10,000
New Accounting Pronouncement, Early Adoption, Effect | Accounting Standards Update 2016-09 | Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect adjustment		$ 10,000

NATURE OF OPERATIONS AND FINA28

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended
	Mar. 31, 2017	Sep. 30, 2017	Aug. 31, 2017	May 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross		$ 5,965,581			$ 6,272,507
Regulatory assets		367,000			281,000
Reclassed to accumulated depreciation		2,153,176			2,385,053
Electricity Generation Plant, Non-Nuclear | San Juan Unit 2
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in plant	$ (224,000)
Net Cost of Removal
Public Utility, Property, Plant and Equipment [Line Items]
Reclassed to accumulated depreciation				$ 87,000
Generation Facility Retirement Costs
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in regulatory assets	$ (14,000)
Regulatory assets		83,000			$ 0
Generation Facility Retirement Costs | Navajo
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross		(52,000)
Regulatory assets		$ 52,000
Generation Facility Retirement Costs | Sundt
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross			$ (32,000)
Regulatory assets			$ 32,000

REGULATORY MATTERS (2017 Rate O

REGULATORY MATTERS (2017 Rate Order) (Details) - Arizona Corporation Commission $ in Millions	Feb. 27, 2017USD ($)
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
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase	$ 81.5
Springerville Unit One
Public Utilities, General Disclosures [Line Items]
Purchased undivided interest in Springerville Unit 1	50.50%
Springerville Unit One | Non-fuel Component of Base Rate
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) $ in Millions	1 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)	Feb. 29, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)$ / kWh	Sep. 30, 2016USD ($)	Dec. 31, 2025	Dec. 31, 2016USD ($)
Purchased Power and Fuel Adjustment Clause
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			$ 20		$ 20			$ 38
Renewable Energy Program
Public Utilities, General Disclosures [Line Items]
Renewable energy target (percentage)								6.00%
Approved spending budget	$ 54
Approved carryover of unused funds	2
Approved recovery of spending budget	$ 52
Renewable energy actual percentage (percentage)								11.00%
Renewable Energy Program | Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Renewable energy target (percentage)							15.00%
Distributed generation requirement percent of target percentage (percentage)							30.00%
Demand Side Management - Energy Efficiency Standards
Public Utilities, General Disclosures [Line Items]
Recovery revenue						$ 2
Energy Efficiency Standards
Public Utilities, General Disclosures [Line Items]
Approved spending budget		$ 22
Approved carryover of unused funds		8
Approved recovery of spending budget		$ 14
Lost Fixed Cost Recovery Mechanism - Energy Efficiency Standards
Public Utilities, General Disclosures [Line Items]
Recovery revenue			$ 6	$ 5	$ 17	$ 14
Cap on increase in lost fixed cost recovery rate (percentage)					2.00%
Effective March 2017 through March 2018 | Purchased Power and Fuel Adjustment Clause
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 | Purchased Power and Fuel Adjustment Clause
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 | Purchased Power and Fuel Adjustment Clause
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	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 367,000	$ 281,000
Less Current Portion	66,899	56,340
Total Non-Current Regulatory Assets	299,943	225,453
Pension and Other Postretirement Benefits (Note 7)
Regulatory Assets [Line Items]
Total Regulatory Assets	123,000	128,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 83,000	0
Final Mine Reclamation and Retiree Health Care Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	20 years
Total Regulatory Assets	$ 34,000	27,000
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 31,000	29,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 29,000	23,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 24,000	23,000
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	6 years
Total Regulatory Assets	$ 14,000	17,000
Amortization period authorized to recover leasehold improvement costs at Springerville Unit 1 (years)	10 years
Sundt Coal Handling Facilities
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 0	14,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 29,000	$ 20,000

REGULATORY MATTERS (Regulator32

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	May 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 272,000		$ 377,000
Less Current Portion	66,066		76,069
Total Non-Current Regulatory Liabilities	205,546		300,700
Reclassed to accumulated depreciation	2,153,176		2,385,053
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	180,000		270,000
Reclassed to accumulated depreciation		$ 87,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 43,000		32,000
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 20,000		38,000
Deferred Investment Tax Credits
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	20,000		23,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 9,000		$ 14,000

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts	$ (6,000)	$ (5,000)
Accounts Receivable, Net	186,007	124,934
Customer
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	118,000	74,000
Customer | Unbilled
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	49,000	34,000
Customer | Due from Affiliates (Note 4)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	7,000	9,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	$ 18,000	$ 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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Receivable—Due from Related Parties	$ 7		$ 7		$ 9
Accounts Payable—Due to Related Parties	3		3		2
Transmission Revenues, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Transmission Revenues	2	$ 2	5	$ 5
Control Area Services, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Control Area Services	1	1	2	2
Common Costs, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Common Costs	4	3	12	10
Supplemental Workforce, SES
Related Party Transaction, Due to/from Related Party [Abstract]
Supplemental Workforce	4	3	11	10
Corporate Services, UNS Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate Services	1	1	4	5
Management fee	1	1	3	4
Corporate Services, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate Services	1	$ 1	$ 3	$ 3
Uns Energy Corporation
Related Party Transaction, Due to/from Related Party [Abstract]
Massachusetts Formula - TEP's allocation (percentage)			82.00%
UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Receivable—Due from Related Parties	5		$ 5		7
Accounts Payable—Due to Related Parties	1		1		0
UNS Gas
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Receivable—Due from Related Parties	2		2		2
SES
Related Party Transaction, Due to/from Related Party [Abstract]
Accounts Payable—Due to Related Parties	$ 2		$ 2		$ 2

RELATED PARTY TRANSACTIONS (Con

RELATED PARTY TRANSACTIONS (Contribution From and Dividend Declared and Paid To Parent) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Related Party Transactions [Abstract]
Dividends Declared to UNS Energy	$ 35,000	$ 20,000	$ 35,000	$ 20,000
Payments of Dividends	$ 35,000	$ 20,000	$ 35,000	$ 20,000

DEBT, CREDIT FACILITY, AND CA36

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Narrative) (Details) - Line of Credit	1 Months Ended
	Oct. 31, 2017facility	Sep. 30, 2017USD ($)
Revolving Credit Facility And Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 250,000,000
Revolving Credit Facility And Letter of Credit | Subsequent Event
Debt Instrument [Line Items]
Number of extensions | facility	2
Period of extension (years)	1 year
Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 50,000,000

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended
	May 30, 2017	Jan. 31, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Commitments And Contingencies [Line Items]
Loss contingency accrual, provision			$ 9		$ 22
Loss contingency, accrual, reversal	$ 5
FERC Refund Orders | Other Income | Settled Litigation
Commitments And Contingencies [Line Items]
Amount awarded from other party		$ 8
Other Current Liabilities | FERC Refund Orders
Commitments And Contingencies [Line Items]
Loss contingency accrual						$ 5
Navajo, San Juan, Four Corners
Commitments And Contingencies [Line Items]
Share of reclamation costs anticipated				$ 61
Navajo, San Juan, Four Corners | Other Liabilities
Commitments And Contingencies [Line Items]
Environmental exit costs, costs accrued to date				$ 32		$ 26

COMMITMENTS AND CONTINGENCIES38

COMMITMENTS AND CONTINGENCIES (PERFORMANCE GUARANTEES) (Details) - Performance Guarantee	Sep. 30, 2017USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations, current carrying value	$ 0
Four Corner
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure, undiscounted	250,000,000
Navajo, San Juan, Luna
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure, undiscounted	$ 0

EMPLOYEE BENEFIT PLANS (Net Per

EMPLOYEE BENEFIT PLANS (Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 3	$ 3	$ 9	$ 9
Interest Cost	3	4	11	11
Expected Return on Plan Assets	(6)	(5)	(18)	(17)
Amortization of Net Loss	2	1	6	5
Net Periodic Benefit Cost	2	3	8	8
Other Postretirement Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1	3	3
Interest Cost	1	1	2	2
Expected Return on Plan Assets	(1)	0	(1)	(1)
Amortization of Net Loss	0	0	0	0
Net Periodic Benefit Cost	$ 1	$ 2	$ 4	$ 4

EMPLOYEE BENEFIT PLANS (Textual

EMPLOYEE BENEFIT PLANS (Textual) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Retirement Benefits [Abstract]
Contribution for the year	$ 9
Expected contribution for the next fiscal year	$ 0

SUPPLEMENTAL CASH FLOW INFORM41

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Other Noncash Investing and Financing Items [Abstract]
Net Cost of Removal Increase (Decrease)	$ (88)	$ 3
Accrued Capital Expenditures	18	16
Additions to Utility Plant, Springerville Unit 1 Settlement	$ 0	$ 5

FAIR VALUE MEASUREMENTS AND D42

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Textual) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Transfers out of level 3	$ 0	$ 0	$ 0	$ 0

FAIR VALUE MEASUREMENTS AND D43

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Assets
Cash Equivalents	$ 59	$ 23
Restricted Cash	8	7
Energy Derivative Contract Assets - Regulatory Recovery	1	3
Energy Derivative Contract Assets - No Regulatory Recovery	4	2
Total Assets	72	35
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(7)	(3)
Energy Derivative Contracts, No Regulatory Recovery	(1)
Interest Rate Swap	(1)	(2)
Total Liabilities	(9)	(5)
Net Total Assets (Liabilities)	63	30
Level 1
Assets
Cash Equivalents	59	23
Restricted Cash	8	7
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	67	30
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Energy Derivative Contracts, No Regulatory Recovery	0
Interest Rate Swap	0	0
Total Liabilities	0	0
Net Total Assets (Liabilities)	67	30
Level 2
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	0	3
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	0	3
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(7)	(2)
Energy Derivative Contracts, No Regulatory Recovery	0
Interest Rate Swap	(1)	(2)
Total Liabilities	(8)	(4)
Net Total Assets (Liabilities)	(8)	(1)
Level 3
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	1	0
Energy Derivative Contract Assets - No Regulatory Recovery	4	2
Total Assets	5	2
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	(1)
Energy Derivative Contracts, No Regulatory Recovery	(1)
Interest Rate Swap	0	0
Total Liabilities	(1)	(1)
Net Total Assets (Liabilities)	$ 4	$ 1

FAIR VALUE MEASUREMENTS AND D44

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Energy Derivative Contracts
Derivative Assets
Gross Amount Recognized in the Balance Sheets	$ 5	$ 5
Counterparty Netting of Energy Contracts	2	2
Cash Collateral Received	0	0
Net Amount	3	3
Derivative Liabilities
Gross Amount Recognized in the Balance Sheets	(8)	(3)
Counterparty Netting of Energy Contracts	(2)	(2)
Cash Collateral Posted	0	0
Net Amount	(6)	(1)
Interest Rate Swap
Derivative Liabilities
Gross Amount Recognized in the Balance Sheets	(1)	(2)
Counterparty Netting of Energy Contracts	0	0
Cash Collateral Posted	0	0
Net Amount	$ (1)	$ (2)

FAIR VALUE MEASUREMENTS AND D45

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Derivative [Line Items]
Cash Flow Hedge Loss to be Reclassified within Twelve Months	$ 1
Interest Rate Swap
Derivative [Line Items]
Derivative Liability, Notional Amount	$ 18

FAIR VALUE MEASUREMENTS AND D46

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Realized Losses From Cash Flow Hedges [Line Items]
Capital Lease Interest Expense	$ 613	$ 821	$ 1,941	$ 2,534
Interest Rate Swap
Realized Losses From Cash Flow Hedges [Line Items]
Capital Lease Interest Expense	$ 0	$ 0	$ 1,000	$ 1,000

FAIR VALUE MEASUREMENTS AND D47

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Percent of long-term trading contract gains shared with ratepayers (percentage)			10.00%
Energy Derivative Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$ (1)	$ 1	$ (6)	$ 10

FAIR VALUE MEASUREMENTS AND D48

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Sep. 30, 2017GWhBTU	Dec. 31, 2016GWhBTU
Power Contracts GWh
Derivative Volume [Line Items]
Derivatives Volumes | GWh	3,840	2,610
Gas Contracts BBtu
Derivative Volume [Line Items]
Derivatives Volumes | BTU	29,261,000,000,000	12,355,000,000,000

FAIR VALUE MEASUREMENTS AND D49

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 - Market approach - Forward Power Contracts $ in Millions	Sep. 30, 2017USD ($)$ / megawatt_hour	Dec. 31, 2016USD ($)$ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets | $	$ 5	$ 2
Derivative Liabilities | $	$ (1)	$ (1)
Minimum
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh (usd per MWh) | $ / megawatt_hour	17.55	20.90
Maximum
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh (usd per MWh) | $ / megawatt_hour	34.05	40

FAIR VALUE MEASUREMENTS AND D50

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning of Period	$ 4	$ 3	$ 1	$ (2)
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	1	1	3	3
Wholesale Revenues	0	0	4	3
Settlements	(1)	(1)	(4)	(1)
End of Period	4	3	4	3
Gains (Losses), Assets (Liabilities) still held	$ 0	$ 0	$ 4	$ 3

FAIR VALUE MEASUREMENTS AND D51

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Sep. 30, 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	$ 21,000,000	$ 8,000,000
Additional collateral required to post if credit-risk contingent features are triggered	21,000,000
Amount relating to outstanding net payable balances for settled positions
Derivative [Line Items]
Additional collateral required to post if credit-risk contingent features are triggered	14,000,000
Line of Credit Collateral
Derivative [Line Items]
LOCs as credit enhancements with counterparties	$ 0

FAIR VALUE MEASUREMENTS AND D52

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Face Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities	$ 1,466	$ 1,466
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities	$ 1,546	$ 1,472