Tucson Electric Power 10-K 16 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 15, 2017	Jun. 30, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	100,122
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filer	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		32,139,434
Entity Public Float			$ 0

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues
Retail	$ 989,580	$ 1,021,543	$ 970,145
Wholesale	117,341	167,020	158,323
Other	128,074	117,981	141,433
Total Operating Revenues	1,234,995	1,306,544	1,269,901
Operating Expenses
Fuel	289,862	305,559	297,537
Purchased Power	85,354	124,764	152,922
Transmission and Other PPFAC Recoverable Costs	23,781	24,798	18,179
Increase (Decrease) to Reflect PPFAC Recovery Treatment	21,064	39,787	(11,194)
Total Fuel and Purchased Power	420,061	494,908	457,444
Operations and Maintenance	353,905	345,356	378,877
Depreciation	146,097	138,093	126,520
Amortization	22,498	19,261	28,567
Taxes Other Than Income Taxes	49,303	49,623	47,805
Total Operating Expenses	991,864	1,047,241	1,039,213
Operating Income	243,131	259,303	230,688
Other Income (Deductions)
Other Income	111	93	208
Other Income	5,636	6,647	8,598
Other Expense	(3,019)	(2,833)	(12,735)
Appreciation (Depreciation) in Value of Investments	2,147	(142)	1,371
Total Other Income (Deductions)	4,875	3,765	(2,558)
Interest Expense
Long-Term Debt	62,015	61,159	60,577
Capital Leases	3,356	3,994	10,249
Other Interest Expense	531	1,134	810
Interest Capitalized	(1,710)	(2,732)	(3,755)
Total Interest Expense	64,192	63,555	67,881
Income Before Income Taxes	183,814	199,513	160,249
Income Tax Expense	59,376	71,719	57,911
Net Income	$ 124,438	$ 127,794	$ 102,338

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net Income	$ 124,438	$ 127,794	$ 102,338
Other Comprehensive Income (Loss)
Net of Income Tax (Expense) Benefit of $(420), $(821), and $(1,140)	652	1,261	1,675
Supplemental Executive Retirement Plan Adjustments:	(643)	101	(1,725)
Total Other Comprehensive Income (Loss), Net of Tax	9	1,362	(50)
Total Comprehensive Income	$ 124,447	$ 129,156	$ 102,288

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	$ 420	$ 821	$ 1,140
Income Tax on Supplemental Executive Retirement Plan Adjustments	$ (399)	$ 63	$ (1,068)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Cash Flows [Abstract]
Net Income	$ 124,438	$ 127,794	$ 102,338
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities:
Depreciation Expense	146,097	138,093	126,520
Amortization Expense	22,498	19,261	28,567
Amortization of Debt Issuance Costs	2,853	3,043	2,626
Use of Renewable Energy Credits for Compliance	17,618	19,731	17,818
Deferred Income Taxes	59,367	72,026	59,024
Pension and Other Postretirement Benefits Expense	15,338	18,588	13,648
Pension and Other Postretirement Benefits Funding	(13,459)	(30,682)	(14,388)
Allowance for Equity Funds Used During Construction	(4,522)	(5,352)	(6,677)
Fortis Acquisition Direct Customer Benefit	0	0	18,870
FERC Transmission Refund Payable	4,878	0	0
Changes in Current Assets and Current Liabilities:
Accounts Receivable	7,809	(3,019)	(12,886)
Materials, Supplies, and Fuel Inventory	7,627	(8,758)	666
Regulatory Assets	(12,147)	18,002	(12,777)
Accounts Payable and Accrued Charges	14,284	(13,917)	(8,763)
Regulatory Liabilities	18,012	10,921	8,388
Other, Net	14,773	(797)	(9,311)
Net Cash Flows—Operating Activities	425,464	364,934	313,663
Cash Flows from Investing Activities
Capital Expenditures	(250,360)	(333,841)	(323,524)
Purchase, Springerville Coal Handling Facilities Lease Assets	0	(120,312)	0
Proceeds from Sale, Springerville Coal Handling Facilities	0	23,656	0
Purchase, Springerville Unit 1 Assets	(85,000)	(45,753)	(19,608)
Purchase, Gila River Unit 3	0	0	(163,938)
Purchase Intangibles, Renewable Energy Credits	(40,949)	(29,184)	(28,334)
Contributions in Aid of Construction	3,432	4,517	15,903
Other, Net	(3,176)	(1,974)	1,863
Net Cash Flows—Investing Activities	(376,053)	(502,891)	(517,638)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facilities	0	148,000	275,000
Repayments of Borrowings, Revolving Credit Facilities	0	(233,000)	(190,000)
Proceeds from Borrowings, Term Loan	0	130,000	0
Repayments of Borrowings, Term Loan	0	(130,000)	0
Proceeds from Issuance, Long-Term Debt	0	299,019	149,168
Repayments, Long-Term Debt	0	(208,600)	0
Dividends Paid to Parent	(50,000)	(50,000)	(40,000)
Payments of Capital Lease Obligations	(14,079)	(13,464)	(165,145)
Payment of Debt Issuance/Retirement Costs	(183)	(3,942)	(1,856)
Contribution from Parent	0	180,000	225,000
Other, Net	(4,871)	1,458	643
Net Cash Flows—Financing Activities	(69,133)	119,471	252,810
Net Increase (Decrease) in Cash and Cash Equivalents	(19,722)	(18,486)	48,835
Cash and Cash Equivalents, Beginning of Period	55,684	74,170	25,335
Cash and Cash Equivalents, End of Period	$ 35,962	$ 55,684	$ 74,170

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Utility Plant
Plant in Service	$ 5,975,139	$ 5,618,435
Utility Plant Under Capital Leases	167,413	131,705
Construction Work in Progress	129,955	102,028
Total Utility Plant	6,272,507	5,852,168
Accumulated Depreciation and Amortization	(2,385,053)	(2,194,301)
Accumulated Amortization of Capital Lease Assets	(104,648)	(99,638)
Total Utility Plant, Net	3,782,806	3,558,229
Investments and Other Property	45,020	39,569
Current Assets
Cash and Cash Equivalents	35,962	55,684
Accounts Receivable, Net	124,934	136,682
Fuel Inventory	25,887	34,600
Materials and Supplies	97,126	94,003
Regulatory Assets	56,340	51,841
Derivative Instruments	4,966	1,808
Assets Held for Sale, Net	0	21,550
Other	13,793	25,904
Total Current Assets	359,008	422,072
Regulatory and Other Assets
Regulatory Assets	225,453	212,312
Derivative Instruments	330	430
Other	37,372	16,866
Total Regulatory and Other Assets	263,155	229,608
Total Assets	4,449,989	4,249,478
Capitalization
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2016 and 2015)	1,296,539	1,296,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	273,408	189,317
Accumulated Other Comprehensive Loss	(4,555)	(4,564)
Total Common Stock Equity	1,559,035	1,474,935
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2016 and 2015)	0	0
Capital Lease Obligations	39,267	55,324
Long-Term Debt, Net	1,453,072	1,451,720
Total Capitalization	3,051,374	2,981,979
Current Liabilities
Current Obligations Under Capital Leases	51,765	14,114
Accounts Payable	89,797	86,274
Accrued Taxes Other than Income Taxes	37,639	37,577
Accrued Employee Expenses	29,465	27,718
Accrued Interest	14,508	14,246
Regulatory Liabilities	76,069	53,077
Customer Deposits	25,778	20,349
Derivative Instruments	2,641	12,174
Other	17,837	7,533
Total Current Liabilities	345,499	273,062
Regulatory and Other Liabilities
Deferred Income Taxes, Net	529,148	468,024
Regulatory Liabilities	300,700	307,286
Pension and Other Postretirement Benefits	131,630	120,336
Derivative Instruments	2,629	4,067
Other	89,009	94,724
Total Regulatory and Other Liabilities	1,053,116	994,437
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 4,449,989	$ 4,249,478

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Capital Stock Expense	Retained Earnings	Accumulated Other Comprehensive Loss
Balances at December 31 at Dec. 31, 2013	$ 925,923	$ 888,971	$ (6,357)	$ 49,185	$ (5,876)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	102,338			102,338
Other Comprehensive Income (Loss), Net of Tax	(50)				(50)
Dividends Declared to Parent	(40,000)			(40,000)
Contribution from Parent	225,000	225,000
Other	2,568	2,568
Balances at December 31 at Dec. 31, 2014	1,215,779	1,116,539	(6,357)	111,523	(5,926)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	127,794			127,794
Other Comprehensive Income (Loss), Net of Tax	1,362				1,362
Dividends Declared to Parent	(50,000)			(50,000)
Contribution from Parent	180,000	180,000
Balances at December 31 at Dec. 31, 2015	1,474,935	1,296,539	(6,357)	189,317	(4,564)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	124,438			124,438
Other Comprehensive Income (Loss), Net of Tax	9				9
Dividends Declared to Parent	(50,000)			(50,000)
Balances at December 31 at Dec. 31, 2016	$ 1,559,035	$ 1,296,539	$ (6,357)	273,408	$ (4,555)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of New Accounting Principle in Period of Adoption				$ 9,653

NATURE OF OPERATIONS AND SUMMAR

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 420,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis. BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with GAAP in the United States, including specific accounting guidance for regulated operations. See Note 2 for additional information regarding regulatory matters. The 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 Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included in the Consolidated Statements of Income. See Note 3 for additional information regarding Utility Plant. Certain amounts from prior periods have been reclassified to conform to the current year 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 PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary 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 December 31, 2016 , the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to its variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent 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. 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 income tax benefit or expense on the statement of income and eliminates the requirement that excess tax benefits be realized before companies can recognize them. On adoption, using the modified retrospective method of transition, TEP recorded a cumulative effect adjustment of $10 million to increase retained earnings and decrease deferred income taxes related to prior period unrecognized excess tax benefits. The impact on the income statement and the statement of cash flows were not significant. TEP elected to recognize forfeitures when they occur. USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheets at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statements during the periods presented. Because these estimates involve judgments based upon the Company's evaluation of relevant facts and circumstances, actual results may differ from these estimates. Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its PV assets as a result of entering into various ground leases or easement agreements. The Company records a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income and the capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers costs associated with its legal AROs as regulatory assets based on the ACC approval of these costs in TEP's depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in the rates charged to retail customers and an obligation is recorded for estimated costs of removal as regulatory liabilities. Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. ACCOUNTING FOR REGULATED OPERATIONS TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through future rate reductions. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets each period and believes recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers. CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. RESTRICTED CASH Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property on the balance sheets. Restricted cash was $7 million and $4 million as of December 31, 2016 and 2015 , respectively. ALLOWANCE FOR DOUBTFUL ACCOUNTS TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Company's Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2016 2015 2014 Beginning of Period $ 27 $ 5 $ 5 Additions Charged to Cost and Expense 4 2 2 Write-offs (3 ) (3 ) (2 ) Provision for Springerville Unit 1, Third-Party Owners (23 ) 23 — End of Period $ 5 $ 27 $ 5 The allowance for doubtful accounts decreased in 2016 due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims. INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost or market. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in Retail Rates. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory. 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 (AFUDC), less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no income statement impact. AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Other Income on the Consolidated Statements of Income. The average AFUDC rates on regulated construction expenditures are included in the table below: 2016 2015 2014 Average AFUDC Rates 7.47 % 6.12 % 7.30 % 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. See Note 3 for additional information regarding Utility Plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant: 2016 2015 2014 Average Annual Depreciation Rates 2.85 % 2.83 % 2.99 % Utility Plant Under Capital Leases TEP finances the Springerville Common Facilities with capital leases. The capital lease expense incurred consists of Amortization Expense and Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 for additional information regarding Utility Plant and Note 6 for additional information related to the lease terms. Computer Software Costs Costs incurred to purchase and develop internal use computer software are capitalized and those costs are amortized over the estimated economic life of the product. If the software is no longer useful or impaired, the carrying value is reduced and charged to expense. EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates. DEFERRED FINANCING COSTS Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt, as this approximates the effective interest method. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to line-of-credit arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt. OPERATING REVENUES Revenues related to the sale of energy are recognized when services or commodities are delivered to customers. The billing of electric sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates. For purchased power and wholesale revenue contracts that are settled financially, TEP nets the revenue contracts with the purchased power contracts and reflects the amount in Wholesale Revenues on the Consolidated Statements of Income. TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned. The ACC has authorized mechanisms for LFCR mechanism related to kWh sales lost due to EE Standards and distributed generation. Revenues are recognized in the period that verifiable energy savings occur. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE TEP recovers actual fuel, purchased power and transmission costs through base fuel rates and a PPFAC to provide electric service to retail customers. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters. RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s 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 in 2025 , with distributed generation 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. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge until such costs are reflected in TEP's non-fuel base rates. TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020 . Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP recognizes RES and DSM surcharge revenue in Retail Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC. When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. TEP had $24 million and $8 million of RECs as of December 31, 2016 and 2015 , respectively. RECs are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 for additional information regarding regulatory matters. INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense on the Consolidated Statements of Income. Prior to 1990, TEP flowed through to customers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory assets include income taxes recoverable through future rates, which reflects the future revenues due to TEP from customers as these tax benefits reverse. See Note 2 for additional information regarding regulatory matters. TEP accounts for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income ax expense in the year the credit arises. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS. TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statements. FAIR VALUE As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 11 for additional information regarding fair value. DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to meet forecasted load and reserve requirements, to reduce exposure to energy commodity price volatility and to hedge interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, those derivative instruments are recognized as either assets or liabilities on the Consolidated Balance Sheets and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Income. For derivatives designated as hedging contracts, TEP formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy. For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 11 for additional information regarding derivative instruments. PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited health care and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects to recover these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 8 for additional information regarding the employee benefit plans.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2016
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 in the rate case filed by TEP in November 2015. TEP's rate filing was based on a test year ended June 30, 2015. The 2017 Rate Order approved new rates to be effective on or before March 1, 2017. The 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 Springerville Unit 1 purchased by TEP in September 2016; • a 7.04% return on original cost rate base, which includes a cost of equity component of 9.75% and a cost of debt component of 4.32% ; and • adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1. The ACC deferred TEP's proposed changes to net metering and rate design for new DG customers to Phase 2, which is expected to begin in the second quarter of 2017. TEP cannot predict the outcome of this proceeding. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12 -month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12 -month period. The PPFAC bank balance was over-collected by $38 million and $18 million as of December 31, 2016 and 2015 , respectively. In February 2017, the ACC approved in the 2017 Rate Order 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 October 2014 through March 2015 0.50 May 2014 through September 2014 0.10 July 2013 through April 2014 (0.14 ) Renewable Energy Standard The ACC’s 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 May 2016, the ACC approved TEP's 2016 RES implementation plan of $57 million , which was partially offset by applying approximately $9 million of previously recovered carryover funds. TEP has been approved to recover the remaining $48 million through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer installed DG; (iii) depreciation and a return on certain TEP investments in company-owned solar projects; and (iv) various other program costs. TEP recognized approximately $3 million of revenue in 2016 as a return on company-owned solar projects. 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. In July 2016, TEP submitted its application for the 2017 RES implementation plan with a budget amount of $54 million . TEP expects to recover less than $1 million of revenue in 2017 through the RES surcharge as a return on certain company-owned solar projects. This amount reflects the return and related recovery on projects that are not included in TEP’s Retail Rates. In addition, TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism. TEP expects to receive a decision on its 2017 RES implementation plan in the first half of 2017. The percentage of retail kWh sales attributable to the 2016 RES renewable energy requirement was approximately 10% , exceeding the overall 2016 requirement of 6% . Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain distributed generation RECs, 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 Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020 . As of December 2016 , TEP’s cumulative annual energy savings were approximately 12% . TEP’s compliance with the EE Standards is governed by the ACC’s approval of its annual implementation plan. TEP is required to implement cost-effective DSM programs to comply with the ACC's EE Standards. The EE Standards provide for a DSM surcharge for regulated utilities to recover from retail customers the costs to implement DSM programs as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 2016 , $3 million in 2015 , and $2 million in 2014 related to performance, included in Retail Revenues on the Consolidated Statements of Income. In February 2016, the ACC approved TEP's 2016 energy efficiency implementation plan, including recovery of approximately $14 million from retail customers for new and existing DSM programs. Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the LFCR mechanism. TEP notified the ACC that it would not file a 2017 implementation plan and will continue its 2016 plan through the end of 2017 without change. TEP will file its 2018 implementation plan by June 1, 2017. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and meeting distributed generation targets. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of TEP's applicable retail revenues. TEP recorded a regulatory asset and recognized LFCR revenues of $18 million in 2016 , $12 million in 2015 , and $11 million in 2014 . LFCR revenues are included in Retail Revenues on the Consolidated Statements of Income. Appellate Review of Rate Decisions In a 2015 appellate challenge to two ACC rate decisions regarding a water company, the Court of Appeals for the State of Arizona considered the issue of how the ACC should determine a utility’s “fair value,” as specified in the Arizona Constitution, in connection with authorizing recovery of costs through rate adjustors outside of a rate case. The Court reversed the ACC’s method of finding fair value in that case and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. In February 2016, the Arizona Supreme Court granted the ACC’s request for review of this decision. In August 2016, the Supreme Court vacated the Court of Appeals decision and confirmed the ACC’s decision regarding the rate adjustor at issue. FERC COMPLIANCE In 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP recording $22 million in time value refunds in 2016. See Note 7 for additional information related to FERC compliance associated with these transmission contracts. REGULATORY ASSETS AND LIABILITIES Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of the leasehold improvements at Springerville Unit 1 and the coal handling facilities at Sundt, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs, TEP does not pay a return on regulatory liabilities. The regulatory assets and liabilities recorded in the Consolidated Balance Sheets are summarized in the table below: Remaining Recovery Period (years) December 31, (dollars in millions) 2016 2015 Regulatory Assets Pension and Other Postretirement Benefits (Note 8) Various $ 128 $ 120 Income Taxes Recoverable through Future Rates (1) Various 29 26 Final Mine Reclamation and Retiree Health Care Costs (2) 21 27 28 Property Tax Deferrals (3) 1 23 21 Lost Fixed Cost Recovery 1 23 16 Springerville Unit 1 Leasehold Improvements (4) 7 17 21 Sundt Coal Handling Facilities (5) Plant Life 16 — Derivatives (Note 11) 3 2 12 Other Regulatory Assets Various 16 20 Total Regulatory Assets 281 264 Less Current Portion 1 56 52 Total Non-Current Regulatory Assets $ 225 $ 212 Regulatory Liabilities Net Cost of Removal for Interim Retirements (6) Various $ 270 $ 264 Purchased Power and Fuel Adjustment Clause 1 38 18 Renewable Energy Standard Various 32 25 Deferred Investment Tax Credits (7) Various 23 32 Other Regulatory Liabilities Various 14 21 Total Regulatory Liabilities 377 360 Less Current Portion 1 76 53 Total Non-Current Regulatory Liabilities $ 301 $ 307 (1) Income Taxes Recoverable through Future Rates are amortized over the life of the assets. See Note 1 and Note 12 for additional information regarding income taxes. (2) Final Mine Reclamation and Retiree Health Care Costs represent costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC when paid. The majority of the final mine reclamation costs are expected to occur through 2037 . (3) Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities to recover property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. (4) Springerville Unit 1 Leasehold Improvements represent investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year amortization period. (5) In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP will apply excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. (6) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future AROs net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. (7) Accumulated Deferred Investment Tax Credits (ITC) represent federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. IMPACTS OF REGULATORY ACCOUNTING If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.

UTILITY PLANT AND JOINTLY-OWNED

UTILITY PLANT AND JOINTLY-OWNED FACILITIES	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Utility Plant And Jointly Owned Facilities [Text Block]	UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (4) Average Remaining Life in Years (4) December 31, (dollars in millions) 2016 2015 Plant in Service Generation Plant 3.31% 22 $ 2,866 $ 2,612 Transmission Plant 1.48% 32 1,024 1,008 Distribution Plant 2.08% 35 1,512 1,456 General Plant 5.48% 11 381 358 Intangible Plant, Software Costs and Other (1) Various Various 185 179 Plant Held for Future Use — — 7 5 Total Plant in Service (2) $ 5,975 $ 5,618 Utility Plant under Capital Leases (3) $ 167 $ 132 (1) Unamortized computer software costs were $52 million and $45 million as of December 31, 2016 and 2015 , respectively. The amortization of computer software costs were $17 million in 2016 , $14 million in 2015 , and $17 million in 2014 . Intangible Plant, Software Costs and Other primarily represents computer software. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and its average remaining life of three years for large enterprise software . (2) Included in Plant in Service are plant acquisition adjustments of $(139) million and $(97) million as of December 31, 2016 and 2015 , respectively. (3) In 2016 , TEP committed to purchase an undivided ownership interest in the Springerville Common Facilities upon the expiration of the first lease term in December 2017. As a result of this commitment, Utility Plant Under Capital Leases increased by the present value of the purchase commitment. See Note 6 for additional information regarding the Springerville leases. (4) The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant. Annual Depreciation Rate and Average Remaining Life in Years are based on the 2012 depreciation study available for the major classes of Plant in Service. TEP will implement new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order. Utility Plant Under Capital Leases All assets included in Utility Plant Under Capital Leases are used in generation operations and amortized over the primary lease term. As of December 31, 2016 , Utility Plant Under Capital Leases represent an undivided one-half interest in certain Springerville Common Facilities. See Note 6 for additional information regarding Springerville leases. The following table shows the amount of lease expense incurred for capital leases: Years Ended December 31, (in millions) 2016 2015 2014 Lease Expense Interest Expense Included in: Interest Expense, Capital Leases $ 3 $ 4 $ 10 Operating Expenses, Fuel — — 1 Amortization of Capital Lease Assets Included in: Operating Expenses, Fuel — 2 6 Operating Expenses, Amortization 5 6 16 Total Lease Expense $ 8 $ 12 $ 33 SPRINGERVILLE ACQUISITION In February 2016, TEP entered into an agreement 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 undivided interest in Springerville Unit 1 for $85 million . The purchase increased TEP's total ownership interest to 100% . See Note 7 for additional information regarding the settlement. JOINTLY-OWNED FACILITIES As of December 31, 2016 , TEP was a participant in the following jointly-owned generation facilities and transmission systems: (in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Units 1 and 2 50.0% $ 496 $ 3 $ 262 $ 237 Navajo Units 1, 2, and 3 7.5% 149 4 114 39 Four Corners Units 4 and 5 7.0% 110 27 76 61 Luna Energy Facility 33.3% 55 — 2 53 Gila River Unit 3 75.0% 202 3 59 146 Gila River Common Facilities 18.8% 25 — 8 17 Springerville Coal Handling Facility (1) 83.0% 201 — 80 121 Transmission Facilities Various 383 3 175 211 Total $ 1,621 $ 40 $ 776 $ 885 (1) As of December 31, 2015, an undivided interest in Springerville Coal Handling Facilities was classified as Assets Held for Sale, Net. In 2016, TEP reclassified the undivided interest in the Springerville Coal Handling Facilities from Assets Held for Sale, Net to Utility Plant on the Consolidated Balance Sheets. See Note 6 for additional information regarding the Springerville Coal Handling Facilities lease interests. As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation. RETIREMENTS San Juan In October 2014, the EPA published a final rule approving a SIP covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017. TEP is a participant in San Juan Unit 2. Given the closure of two units and the desire of certain participants to exit their ownership in San Juan, PNM and the other participants, including TEP, negotiated restructured ownership agreements which became effective upon the sale of SJCC stock in January 2016. As a condition of the New Mexico Public Regulatory Commission’s (NMPRC) approval of the early retirement of San Juan Units 2 and 3, PNM is required to make a filing with the NMPRC in 2018 to demonstrate the ongoing economic viability of San Juan beyond 2022. Under the new restructured ownership agreements, TEP and the other remaining participants have the option to exit their remaining ownership interest in San Juan as of June 30, 2022. As of December 31, 2016 , the NBV of TEP's share in San Juan Unit 2, including construction work in progress, was $98 million . TEP will apply excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. See Note 2 for additional information regarding the 2017 Rate Order. Sundt In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the coal handling facilities at Sundt to a regulatory asset. As of December 31, 2016 , the NBV of the coal handling facilities at Sundt was $16 million . TEP will apply excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. See Note 2 for additional information regarding the 2017 Rate Order. ASSET RETIREMENT OBLIGATIONS The accrual of AROs is primarily related to generation and PV assets and is included in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals in the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Beginning of Period $ 32 $ 28 Liabilities Incurred — 4 Accretion Expense or Regulatory Deferral 2 1 Revisions to the Present Value of Estimated Cash Flows (1) (1 ) (1 ) End of Period $ 33 $ 32 (1) Primarily related to changes in expected cost estimates, in conjunction with changes of asset retirement dates of generation facilities.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2016
Accounts Receivable, Net [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Customer $ 74 $ 79 Due from Affiliates (Note 5) 9 7 Unbilled 34 39 Other (1) 13 39 Allowance for Doubtful Accounts (1) (5 ) (27 ) Accounts Receivable, Net $ 125 $ 137 (1) In 2016, Accounts Receivable—Other and Allowance for Doubtful Accounts decreased due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including Unisource Energy Services, Inc. (UES), UNS Electric, 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 Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Receivables from Related Parties UNS Electric $ 7 $ 6 UNS Gas 2 1 Total Due from Related Parties $ 9 $ 7 Payables to Related Parties SES $ 2 $ 2 UNS Electric — 2 UNS Energy — 2 Total Due to Related Parties $ 2 $ 6 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2016 2015 2014 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 7 $ 6 $ 1 Wholesale Revenues, UNS Electric (1) — 2 3 Control Area Services, UNS Electric (2) 2 2 3 Common Costs, UNS Energy Affiliates (3) 14 12 13 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) 1 1 4 Supplemental Workforce, SES (4) 14 16 16 Corporate Services, UNS Energy (5) 7 7 14 Corporate Services, UNS Energy Affiliates (6) 4 1 1 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates through the applicable Open Access Transmission Tariff. (2) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (4) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (5) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal and audit fees. Beginning in 2015, following the August 2014 Fortis acquisition, it includes Fortis management fees of approximately $6 million in 2016 and $5 million in 2015 . (6) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. CONTRIBUTION FROM PARENT UNS Energy made no equity contributions to TEP in 2016. TEP received contributions from UNS Energy of $180 million in 2015 and $225 million in 2014 . The contributions were used to repay revolving credit loans, redeem bonds, purchase additional generation capacity, and provide additional liquidity to TEP. DIVIDENDS PAID TO PARENT TEP declared and paid $50 million in dividends to UNS Energy in 2016 and 2015 and $40 million in 2014 .

DEBT, CREDIT FACILITY, AND CAPI

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
DEBT	DEBT Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, (dollars in millions) Interest Rate Maturity Date 2016 2015 Notes 2011 Notes 5.15% 2021 $ 250 $ 250 2012 Notes 3.85% 2023 150 150 2014 Notes 5.00% 2044 150 150 2015 Notes 3.05% 2025 300 300 Tax-Exempt Local Furnishings Bonds 2010 Pima A 5.25% 2040 100 100 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 2013 Apache A (1) 1.01% 2032 100 100 Tax-Exempt Pollution Control Bonds 2009 Pima A 4.95% 2020 80 80 2009 Coconino A 5.13% 2032 15 15 2010 Coconino A (2) 1.33% 2032 37 37 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt (3) 1,466 1,466 Less Unamortized Discount and Debt Issuance Costs 13 14 Total Long-Term Debt, Net $ 1,453 $ 1,452 (1) The bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average based on a percentage of an index equal to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in 2018. (2) The bonds are variable rate debt for which rates are reset weekly. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. (3) As of December 31, 2016 , all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by a LOC. DEBT ISSUANCES AND REDEMPTIONS Fixed Rate Debt In February 2015, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to December 2024, with a make-whole premium plus accrued interest. On or after December 2024, TEP may redeem the notes at par plus accrued interest. In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) issued in June 2008 by the Industrial Development Authority (IDA) of Pima County, Arizona for the benefit of TEP. The multi-modal bonds mature in September 2029. As of December 31, 2016 , TEP had not remarketed the repurchased bonds and as a result the bonds were not recorded in Long-Term Debt, Net on the Consolidated Balance Sheets. Variable Rate Debt In August 2015, TEP redeemed two series of variable rate tax-exempt bonds at par with an aggregate principal amount of $79 million prior to maturity. In September 2015, TEP terminated the associated LOCs issued under a revolving credit facility. CREDIT FACILITY In October 2015, TEP entered into a new unsecured credit agreement which replaced its previous credit agreements. The new credit facility includes: (i) a borrowing capacity of $250 million in revolving credit commitments; (ii) an LOC facility with a sublimit of $50 million ; (iii) an original maturity date of October 2020; and (iv) two one -year extensions options of the facility. In October 2016, TEP extended the final maturity date one year to October 2021 as permitted by the credit facility. Pursuant to the one -year extension option, $218 million of the commitments elected to extend to the new maturity date. Interest rates and fees under the credit facility are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.00% for Eurodollar loans or ABR with no spread for ABR loans. TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of December 31, 2016 , TEP had no borrowings outstanding included in Current Liabilities on the Consolidated Balance Sheets. As of February 15, 2017 , there was $250 million available under the revolving credit commitments and LOC facilities. TEP's previous credit agreements provided for a total of $270 million in revolving credit commitments, LOCs supporting variable-rate, tax-exempt bonds, and a $130 million term loan commitment, with original expiration dates of November 2016 and November 2015, respectively. 2010 REIMBURSEMENT AGREEMENT In December 2010, a $37 million LOC was issued to support certain variable rate tax-exempt bonds pursuant to the 2010 Reimbursement Agreement. The LOC has an expiration date of December 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 0.75% per annum based on TEP's current credit ratings. COVENANT COMPLIANCE Certain of TEP's credit and long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. As of December 31, 2016 , TEP was in compliance with the terms of its credit and long-term debt agreements. CAPITAL LEASE OBLIGATIONS The following table details Capital Lease Obligations on the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Capital Lease Obligations $ 91 $ 69 Less Current Obligations Under Capital Leases 52 14 Total Capital Lease Obligations, Non-Current $ 39 $ 55 Springerville Unit 1 Capital Lease Purchases In January 2015, upon expiration of the lease term, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million , the appraised value. With the completion of the purchase, TEP owned 49.5% of Springerville Unit 1, or 192 MW of capacity. In September 2016, TEP purchased the remaining undivided interest in Springerville Unit 1, bringing its total ownership of the assets to 100% . See Note 7 for more information regarding the settlement agreement relating to Springerville Unit 1. Springerville Coal Handling Facilities Lease Purchase In April 2015, upon expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million , bringing its total ownership of the assets to 100% . Upon purchase of the leased interest, TEP reduced Capital Lease Obligations on the Consolidated Balance Sheets for the purchase price. In May 2015, SRP, the owner of Springerville Unit 4, purchased from TEP a 17.05% undivided interest in the Springerville Coal Handling Facilities for approximately $24 million . Tri-State, the lessee of Springerville Unit 3, is obligated to either: (i) buy a 17.05% undivided interest in the facilities for approximately $24 million ; or (ii) continue to make payments to TEP for the use of the facilities. Tri-State had until April 2016 to exercise its purchase option. In March 2016, Tri-State notified TEP that it was exercising its option to purchase the undivided interest in the facilities. As of December 31, 2015, the 17.05% undivided interest in the Springerville Coal Handling Facilities was classified as Assets Held for Sale, Net. However, as of December 31, 2016, TEP's management no longer believed the sale would be completed. As a result, in December 2016 Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities was reclassified as Utility Plant from Assets Held for Sale, Net on the Consolidated Balance Sheets. In 2016 , TEP recorded $1 million of catchup depreciation for the period of time the facilities were recorded in Assets Held for Sale, Net. Springerville Common Facilities Leases The Springerville Common Facilities Leases include: (i) one lease with a fixed purchase price of $38 million and an initial term ending December 2017; and (ii) two leases with a total fixed purchase price of $68 million and initial terms ending January 2021. In December 2016, TEP notified the owner participant and the lessor that TEP had elected to purchase a 17.8% undivided ownership interest in the Springerville Common Facilities at the fixed purchase price of $38 million upon the expiration of the lease expiring in December 2017. Due to TEP's purchase commitment, in December 2016, TEP recorded an increase of $36 million to both Current Obligations Under Capital Leases and Utility Plant Under Capital Leases, which represents the present value of the total purchase commitment, on its Consolidated Balance Sheets. Under the remaining two leases, TEP has options to: (i) renew the leases for periods of two or more years; or (ii) exercise the purchase options under these contracts. In addition, TEP entered into agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions if the Common Facilities Leases are not renewed: (i) TEP will exercise the purchase options under these contracts; (ii) SRP will be obligated to buy a 14% undivided interest in the facilities; and (iii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities. Springerville Common Facilities lease Interest Rate Swap TEP entered into an interest rate swap agreement in 2006 that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. The swap has the effect of fixing the benchmark LIBOR rate on a portion of the amortizing principal balance. The swap matures in January 2020 with interest on the lease debt payable at a swapped rate of 5.77% plus an applicable margin per the lease agreement. The lease debt outstanding as of December 31, 2016 consisted of a notional amount of $23 million on which interest was fixed by the swap and a notional amount of $9 million of debt that was not hedged. The applicable margin was 1.88% as of December 31, 2016 and 2015 . TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 11 for additional information. DEBT MATURITIES Long-term debt, including revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: (in millions) Long-Term Debt (1) Capital Lease Obligations Total Debt Maturities (2) 2017 $ — $ 52 $ 52 2018 100 11 111 2019 37 11 48 2020 80 18 98 2021 250 — 250 Total 2017 - 2021 467 92 559 Thereafter 999 — 999 Less: Imputed Interest — (1 ) (1 ) Total $ 1,466 $ 91 $ 1,557 (1) $37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in 2018. (2) Total long-term debt excludes $10 million of related unamortized debt issuance costs and $3 million of unamortized original issue discount.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS As of December 31, 2016 , TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases: (in millions) 2017 2018 2019 2020 2021 Thereafter Total Fuel, Including Transportation $ 100 $ 76 $ 76 $ 67 $ 43 $ 269 $ 631 Purchased Power 32 — — — — — 32 Transmission 18 19 19 8 4 10 78 Renewable Power Purchase Agreements 64 64 64 63 63 730 1,048 RES Performance-Based Incentives 8 8 8 8 8 59 99 Operating Leases: Land Easements and Rights-of-Way 1 1 1 1 2 75 81 Other 1 1 1 1 1 4 9 Total Purchase Commitments $ 224 $ 169 $ 169 $ 148 $ 121 $ 1,147 $ 1,978 Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBIs costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms. Fuel, Including Transportation TEP has long-term agreements for the purchase and delivery of coal with various expiration dates between 2017 and 2031 . Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect the future cost. In April 2016, Peabody filed for reorganization under Chapter 11 of the Bankruptcy Code. TEP has existing agreements with Peabody to supply coal from the El Segundo and Lee Ranch mines to Springerville and from the Kayenta mine to Navajo. TEP has continued to receive its contracted coal as planned and has sufficient access to coal inventory for the near future. TEP cannot currently predict the outcome of this matter or the range of its potential impact on TEP's coal supply from Peabody. TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2018 and 2040 . Purchased Power TEP has contracts with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts with various expiration dates through the fourth quarter of 2017 . Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2016 . Transmission TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2019 and 2030 . Renewable Power Purchase Agreements TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2030 and 2036 . RES Performance-Based Incentives TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2022 and 2033 . Operating Leases TEP's operating lease expense is primarily for rail cars, office facilities, land easements, and rights-of-way with varying terms, provisions, and expiration dates. TEP's operating lease expense totaled $2 million in 2016 and $3 million in 2015 and 2014 . 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 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 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). The Agreement provided that: (i) TEP would purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million ; and (ii) the Third-Party Owners would pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners. In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the undivided interest in Springerville Unit 1 for $85 million . The purchase increased TEP's total ownership interest to 100% . 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. Claims Related to San Juan Generating Station WildEarth Guardians In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by the OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from the OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against the OSM, including, but not limited to, the OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated the NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with the NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. SJCC was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now proceeding. On July 18, 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM may prepare a new environmental impact statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the federal defendants’ motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provided that, the OSM’s decision approving the mining plan will remain in effect during this process. The order further provides that if the EIS is not completed by August 31, 2019, then an order vacating the approved mine plan will become immediately effective, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact. 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 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 (DOI) 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 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 the 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 APS, the operator of Four Corners, filed a motion to intervene in this matter. APS’ motion was granted in August 2016. Briefing on the merits is expected to extend through May 2017. NTEC, the company that owns the Navajo Mine, filed a motion to intervene in September 2016 for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Navajo Generating Station Lease Amendment Navajo is located on a site that is leased from the Navajo Nation with an initial lease term through 2019 . The Navajo Nation signed a lease amendment in 2013 that would extend the lease from 2019 through 2044 (2013 Navajo Lease Extension). TEP owns 7.5% of Navajo. Since 2014, TEP had accrued additional estimated lease expense of approximately $5 million based on TEP's expectation that the lease would be extended. In December 2016 , TEP reversed its lease amendment liability recorded in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets as management no longer believed the 2013 Navajo Lease Extension was probable. The total lease amendment liability recorded in Regulatory and Other Liabilities—Other as of December 31, 2015 , was $3 million . Mine Reclamation at Generation Facilities Not Operated by TEP TEP pays ongoing reclamation mine costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $61 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The Consolidated Balance Sheets reflect a total liability related to reclamation of $26 million and $25 million as of December 31, 2016 and 2015 , respectively. 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 us 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. Gila River Emissions Compliance In August 2016, Gila River received a Notice of Violation from the Maricopa County Air Quality Department (MCAQD) stating the facility failed to monitor emissions during startup and to properly calibrate carbon monoxide monitors. TEP and UNS Electric own a 75% and 25% , respectively, undivided ownership interest in Gila River Unit 3. Gila River has already performed the necessary corrective actions to address the alleged violations. In December 2016, Gila River signed a settlement agreement with MCAQD resolving all alleged violations. The settlement amount was immaterial to the presentation of TEP's financial statements. FERC Compliance In 2015 and 2016, TEP self-reported to the FERC OE that TEP 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 form of service agreement. 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. As a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded $22 million in time value refunds offsetting Wholesale Revenues on the Consolidated Statements of Income in 2016. Of the total amount recorded, TEP has paid $17 million in 2016 and accrued the remaining $5 million in Current Liabilities—Other on the Consolidated Balance Sheets as of December 31, 2016. In June 2016, to preserve its rights, TEP petitioned the D.C. Circuit Court of Appeals to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. Under the agreement, the counterparty paid TEP $8 million in January 2017 and TEP dismissed the appeal with prejudice. TEP's Compliance Reviews are still under review by the OE. The FERC could impose civil penalties on TEP as a result of the OE's review of the Compliance Reviews. At this time, TEP cannot predict the outcome or range of additional losses, if any. Performance Guarantees TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and with Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments (undiscounted) TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of December 31, 2016 , 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.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS PENSION BENEFIT PLANS TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations. TEP also maintains a SERP for executive management. OTHER POSTRETIREMENT BENEFIT PLAN TEP provides limited health care and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $2 million in 2016 , $4 million in 2015 , and $3 million in 2014 to the VEBA. Other postretirement benefits for unclassified employees are self-funded. REGULATORY RECOVERY TEP records changes in non-SERP pension plans and the other postretirement defined benefit plan, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income (Loss) since SERP expense is not currently recoverable in rates. The following table summarizes pension and other postretirement benefit amounts (excluding tax balances) included in the Consolidated Balance Sheets: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2016 2015 2016 2015 Regulatory Assets $ 123 $ 115 $ 5 $ 5 Accrued Employee Expenses (1 ) (1 ) (2 ) (2 ) Pension and Other Postretirement Benefits (69 ) (57 ) (63 ) (63 ) Accumulated Other Comprehensive Loss, SERP 6 5 — — Net Amount Recognized $ 59 $ 62 $ (60 ) $ (60 ) OBLIGATIONS AND FUNDED STATUS The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2016 and 2015 . The table below summarizes the status of all of TEP’s pension and other postretirement benefit plans. All plans have projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2016 2015 2016 2015 Change in Projected Benefit Obligation Beginning of Period $ 394 $ 407 $ 78 $ 81 Actuarial (Gain) Loss 20 (22 ) — (5 ) Interest Cost 15 17 2 3 Service Cost 12 12 4 4 Benefits Paid (17 ) (20 ) (5 ) (5 ) End of Period 424 394 79 78 Change in Fair Value of Plan Assets Beginning of Period 336 335 13 12 Actual Return on Plan Assets 27 (3 ) 1 — Benefits Paid (17 ) (20 ) (5 ) (5 ) Employer Contributions (1) 8 24 5 6 End of Period 354 336 14 13 Funded Status at End of Period $ (70 ) $ (58 ) $ (65 ) $ (65 ) (1) TEP expects to contribute $11 million to the pension plans in 2017 . The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2016 2015 2016 2015 Net Loss $ 128 $ 117 $ 6 $ 6 Prior Service Cost (Benefit) — 3 (1 ) (1 ) The accumulated benefit obligation aggregated for all pension plans is $384 million and $355 million as of December 31, 2016 and 2015 , respectively. All three pension plans had accumulated benefit obligations in excess of plan assets as of December 31, 2016 . Two of TEP's plans had accumulated benefit obligations in excess of plan assets as of December 31, 2015 . The following table includes information for pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2016 2015 Accumulated Benefit Obligation $ 384 $ 188 Fair Value of Plan Assets 354 169 Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2016 2015 2014 2016 2015 2014 Service Cost $ 12 $ 12 $ 10 $ 4 $ 4 $ 4 Interest Cost 15 17 16 2 3 3 Expected Return on Plan Assets (23 ) (23 ) (21 ) (1 ) (1 ) (1 ) Amortization of Net Loss 7 7 3 — — — Net Periodic Benefit Cost $ 11 $ 13 $ 8 $ 5 $ 6 $ 6 Approximately 19% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income. Beginning in 2016, the Company elected to measure service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Prior to 2016, the Company measured service and interest costs for pension and other postretirement benefits utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. TEP believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans' liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of its plan obligations nor the funded status. TEP accounted for this change as a change in accounting estimate, and accordingly, accounted for it on a prospective basis. The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Current Year Actuarial (Gain) Loss $ 15 $ 5 $ 49 $ 1 $ — $ 3 $ — $ (4 ) $ 5 Amortization of Net Loss (7 ) (7 ) (3 ) — — — — — — Total Recognized (Gain) Loss $ 8 $ (2 ) $ 46 $ 1 $ — $ 3 $ — $ (4 ) $ 5 For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. Estimated amortization from regulatory assets into net periodic benefit cost in 2017 includes the following: (in millions) Pension Benefits Other Postretirement Benefits Net Loss $ 7 $ — Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25 th percentile to the 75 th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes. The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Discount Rate 4.2% 4.5% 4.0% 4.2% Rate of Compensation Increase 2.8% 3.0% N/A N/A The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount Rate, Service Cost 4.8% 4.2% 5.1% 4.6% 3.9% 4.7% Discount Rate, Interest Cost 3.9% 4.2% 5.1% 3.4% 3.9% 4.7% Rate of Compensation Increase 3.0% 3.0% 3.0% N/A N/A N/A Expected Return on Plan Assets 7.0% 7.0% 7.0% 7.0% 7.0% 7.0% The following table includes the assumed health care cost trend rates: December 31, 2016 2015 Next Year 7.6% 7.6% Ultimate Rate Assumed 4.5% 4.5% Year Ultimate Rate is Reached 2037 2036 Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the amounts: One-Percentage- Point Increase One-Percentage- Point Decrease (in millions) December 31, 2016 Increase (Decrease) on Total Service and Interest Cost Components $ 1 $ (1 ) Increase (Decrease) on Other Postretirement Benefit Obligation 7 (6 ) PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement 2016 2015 2016 2015 Asset Category Equity Securities 49 % 49 % 60 % 60 % Fixed Income Securities 41 % 41 % 35 % 35 % Real Estate 8 % 8 % 2 % 2 % Other 2 % 2 % 3 % 3 % Total 100 % 100 % 100 % 100 % As of December 31, 2016 , the fair value of VEBA trust assets was $14 million , of which $5 million were fixed income investments and $9 million were equities. As of December 31, 2015 , the fair value of VEBA trust assets was $13 million , of which $5 million were fixed income investments and $8 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust. The following table sets forth the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2016 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 61 — 61 United States Small Cap — 18 — 18 Non-United States — 67 — 67 Global — 28 — 28 Fixed Income — 144 — 144 Real Estate — 9 19 28 Private Equity — — 7 7 Total $ 1 $ 327 $ 26 $ 354 (in millions) December 31, 2015 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 81 — 81 United States Small Cap — 17 — 17 Non-United States — 67 — 67 Fixed Income — 137 — 137 Real Estate — 8 18 26 Private Equity — — 7 7 Total $ 1 $ 310 $ 25 $ 336 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 100% of real estate assets tracked by the index. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. The following table sets forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2014 $ 7 $ 16 $ 23 Actual Return on Plan Assets: Assets Held at Reporting Date 1 2 3 Purchases, Sales, and Settlements (1 ) — (1 ) Balance as of December 31, 2015 7 18 25 Actual Return on Plan Assets: Assets Held at Reporting Date 1 1 2 Purchases, Sales, and Settlements (1 ) — (1 ) Balance as of December 31, 2016 $ 7 $ 19 $ 26 Pension Plan Investments Investment Goals Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. Risk Management TEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: plan status, plan sponsor financial status and profitability, plan features, and workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes. Relationship between Plan Assets and Benefit Obligations The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation. Target Allocation Percentages The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. Pension Other Postretirement December 31, 2016 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 17% 39% United States Small Cap 5% 5% Non-United States Developed 15% 7% Non-United States Emerging 4% 9% Global Equity 5% —% Global Infrastructure 3% —% Fixed Income 42% 38% Real Estate 8% —% Private Equity 1% —% Total 100% 100% Pension Fund Descriptions For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds. ESTIMATED FUTURE BENEFIT PAYMENTS TEP expects the following benefit payments to be made by the defined benefit pension plans and other postretirement benefit plan, which reflect future service, as appropriate. (in millions) 2017 2018 2019 2020 2021 2022-2026 Pension Benefits $ 18 $ 19 $ 20 $ 22 $ 23 $ 128 Other Postretirement Benefits 4 5 5 6 6 32 DEFINED CONTRIBUTION PLAN TEP offers a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in 2016 , 2015 , and 2014 .

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	SHARE-BASED COMPENSATION 2011 STOCK AND INCENTIVE PLAN The Fortis acquisition of UNS Energy in 2014 resulted in accelerated vesting and expense recognition of all outstanding non-vested UNS Energy share-based awards issued under the UNS Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan). The outstanding non-vested awards would otherwise have been recognized over remaining vesting periods through February 2017. TEP recognized approximately $2 million of expense in 2014 due to the accelerated vesting of the awards. TEP recorded total share-based compensation expense of $5 million for the year ended December 31, 2014. In August 2014, UNS Energy settled all outstanding share-based compensation awards related to the 2011 Plan in cash. 2015 SHARE UNIT PLAN The Human Resources and Governance Committee (Committee) of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (Plan) effective as of January 1, 2015. Under the Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of performance-based share units (PSUs) and time-based restricted share units (RSUs) annually. Each PSU and RSU granted will be valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy awarded PSUs and RSUs as follows: 2016 2015 PSUs 66,974 47,776 RSUs 33,488 23,888 The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $4 million and $2 million as of December 31, 2016 and 2015 , respectively. TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $2 million and $1 million in years ended 2016 and 2015 , respectively, based on its share of UNS Energy's compensation expense.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Years Ended December 31, (in millions) 2016 2015 2014 Interest, Net of Amounts Capitalized $ 61 $ 65 $ 83 Income Taxes — — — 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: Years Ended December 31, (in millions) 2016 2015 2014 Accrued Capital Expenditures $ 29 $ 28 $ 29 Net Cost of Removal of Interim Retirements (1) 8 1 12 Commitment to Purchase Capital Lease Interests 36 — 109 Capital Lease Obligations (2) — — 1 Asset Retirement Obligations (3) (1 ) 3 4 (1) The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings. (2) The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments. (3) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future AROs.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block [Abstract]
FAIR VALUE MEASUREMENTS & 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) 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 ) Net Total Assets (Liabilities) $ 30 $ (1 ) $ 1 $ 30 (in millions) December 31, 2015 Assets Cash Equivalents (1) $ 33 $ — $ — $ 33 Restricted Cash (1) 4 — — 4 Energy Derivative Contracts, Regulatory Recovery (2) — 1 — 1 Energy Derivative Contracts, No Regulatory Recovery (2) — — 1 1 Total Assets 37 1 1 39 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (10 ) (3 ) (13 ) Interest Rate Swap (3) — (3 ) — (3 ) Total Liabilities — (13 ) (3 ) (16 ) Net Total Assets (Liabilities) $ 37 $ (12 ) $ (2 ) $ 23 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds 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 Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property on the Consolidated Balance Sheets. (2) Energy Contracts include gas swap agreements (Level 2), gas options (Level 3), 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 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 LIBOR and is included in Derivative Instruments on the 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) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) (in millions) December 31, 2015 Derivative Assets Energy Derivative Contracts $ 2 $ 1 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (13 ) (1 ) — (12 ) Interest Rate Swap (3 ) — — (3 ) DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its 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. 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, TEP categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both power and gas prices TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for power and for gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission, and line losses. TEP estimates the fair value of gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. 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 in January 2020 . TEP had a purchased power swap to hedge the cash flow risk associated with a long-term power supply agreement which expired in September 2015. 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 . Realized losses from cash flow hedges are shown in the following table: Years Ended December 31, (in millions) 2016 2015 2014 Capital Lease Interest Expense $ 1 $ 2 $ 2 Long-Term Debt Interest Expense — — 1 Purchased Power — 1 1 As of December 31, 2016 , the total notional amount of the interest rate swap was $23 million . Energy Derivative Contracts - Regulatory Recovery TEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC 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 following table: Years Ended December 31, (in millions) 2016 2015 2014 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ 12 $ 6 $ (18 ) Energy Derivative Contracts - No Regulatory Recovery Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For those contracts that qualify as derivatives, TEP records unrealized gains and losses in the income statement, unless and until a normal purchase or normal sale election is made. The unrealized gains and losses on long-term power trading contracts are recorded in the income statement, and 10% of any gains will be shared with ratepayers through the PPFAC, as realized. Derivative Volumes As of December 31, 2016 , TEP has energy contracts that will settle through 2019 . The volumes associated with the energy contracts were as follows: December 31, 2016 2015 Power Contracts GWh 2,610 1,752 Gas Contracts BBtu 12,355 17,214 Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 Level 3 Energy Contracts $ 2 $ (1 ) (in millions) December 31, 2015 Forward Power Contracts Market approach $ 1 $ (2 ) Market price per MWh $ 19.20 $ 31.35 Gas Option Contracts Option model — (1 ) Market price per MMbtu $ 2.17 $ 2.69 Gas volatility 31.0% 58.3% Level 3 Energy Contracts $ 1 $ (3 ) 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 assets and liabilities classified as Level 3 in the fair value hierarchy: Years Ended December 31, (in millions) 2016 2015 Beginning of Period $ (2 ) $ (9 ) Gains (Losses) Recorded (1) Net Regulatory Assets or Liabilities, Derivative Instruments 2 (4 ) Electric Wholesale Sales 4 3 Settlements (3 ) 8 End of Period $ 1 $ (2 ) (1) Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $1 million and $(1) million for the years ended December 31, 2016 and 2015 , respectively. CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of energy and 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 collateral posted, and then allocates the credit risk adjustment to all individual contracts. Material adverse changes could trigger credit risk-related contingent features. The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $8 million as of December 31, 2016 , compared with $20 million as of December 31, 2015 . As of December 31, 2016 , TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on December 31, 2016 , TEP would have been required to post an additional $8 million of collateral of which $8 million relates to outstanding net payable balances for settled positions. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. TEP uses the following methods and assumptions for estimating the fair value of financial instruments: • Borrowings under revolving credit facilities approximate the fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below. • For long-term debt, TEP uses quoted market prices, when available, or calculates the present value of remaining cash flows at the balance sheet date. When calculating present value, the Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. The Company also incorporates the impact of its own credit risk using a credit default swap rate. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Face Value Fair Value December 31, (in millions) 2016 2015 2016 2015 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,472 $ 1,529

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following: Years Ended December 31, (in millions) 2016 2015 2014 Federal Income Tax Expense at Statutory Rate $ 64 $ 70 $ 56 State Income Tax Expense, Net of Federal Deduction 6 8 7 Federal/State Tax Credits (8 ) (8 ) (5 ) Allowance for Equity Funds Used During Construction (1 ) (1 ) (2 ) Deferred Tax Asset Valuation Allowance (2 ) 1 — Other — 2 2 Total Federal and State Income Tax Expense $ 59 $ 72 $ 58 Income tax expense included in the income statements consists of the following: Years Ended December 31, (in millions) 2016 2015 2014 Current Tax Expense (Benefit) Federal $ — $ — $ (1 ) State — — — Total Current Tax Expense (Benefit) — — (1 ) Deferred Tax Expense (Benefit) Federal 60 66 54 Federal Investment Tax Credits (6 ) (6 ) (4 ) State 5 12 9 Total Deferred Tax Expense (Benefit) 59 72 59 Total Federal and State Income Tax Expense $ 59 $ 72 $ 58 The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2016 2015 Gross Deferred Income Tax Assets Capital Lease Obligations $ 35 $ 27 Net Operating Loss Carryforwards 129 156 Customer Advances and Contributions in Aid of Construction 20 20 Alternative Minimum Tax Credit 25 24 Accrued Postretirement Benefits 23 23 Emission Allowance Inventory 9 9 Investment Tax Credit Carryforward 32 32 Other 60 53 Total Gross Deferred Income Tax Assets 333 344 Deferred Tax Assets Valuation Allowance — (4 ) Gross Deferred Income Tax Liabilities Plant, Net (774 ) (750 ) Capital Lease Assets, Net (24 ) (12 ) Pensions (26 ) (27 ) Other (38 ) (19 ) Total Gross Deferred Income Tax Liabilities (862 ) (808 ) Net Deferred Income Tax Liabilities $ 529 $ 468 TEP recorded no valuation allowance against credit and loss carryforward deferred tax assets as of December 31, 2016 and a $4 million valuation allowance against credit and loss carryforward deferred tax assets as of December 31, 2015 . Management believes TEP will produce sufficient taxable income in the future to realize credit and loss carryforwards before they expire. As of December 31, 2016 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 364 2031-34 State Credits 10 2017-29 Alternative Minimum Tax Credit 25 None Investment Tax Credits 32 2032-36 Uncertain Tax Positions A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2016 2015 Beginning of Period $ 5 $ 4 Additions Based on Tax Positions Taken in the Current Year 7 1 End of Period $ 12 $ 5 Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million as of December 31, 2016 and 2015 . TEP recorded no interest expense during 2016 and 2015 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2016 and 2015 . TEP has been audited by the IRS through tax year 2010. TEP is not currently under audit by any federal or state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of IRS audits, but the Company is unable to determine the amount of change.

RECENTLY ISSUED ACCOUNTING PRON

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS TEP considers the applicability and impact of all accounting standard updates issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on the Company's consolidated financial position, results of operations, or disclosures. REVENUE FROM CONTRACTS WITH CUSTOMERS In May 2014, the FASB issued an accounting standard update that will eliminate the transaction and industry-specific revenue recognition guidance under current GAAP and replace it with a principles-based approach for determining revenue recognition. In July 2015, the FASB voted to defer the effective date of the revenue recognition standard by one year, and TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2018. The Company has elected not to early adopt this standard. The revenue standard requires entities to apply the guidance retrospectively or under the modified retrospective approach by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. TEP expects to use the modified retrospective approach. Retail and wholesale sales of energy based on regulator-approved tariff rates represent TEP’s primary sources of revenue. TEP does not expect that the adoption of this standard will have a material impact on the recognition of revenue from energy sales to retail or wholesale customers. Certain industry specific interpretative issues, including contributions in aid of construction, remain outstanding. The conclusions reached, if different than currently anticipated, could change the Company's expected method of adoption and have a material impact on the Company’s consolidated financial statements and related disclosures. LEASES In February 2016, the FASB issued an accounting standard update that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under current GAAP. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures. RESTRICTED CASH In November 2016, the FASB issued an accounting standard update that will require entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. The standard is effective for annual and interim periods beginning January 1, 2018, and is to be applied using a retrospective approach. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA	QUARTERLY FINANCIAL DATA (UNAUDITED) TEP's quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. TEP's utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. First Quarter Second Quarter Third Quarter Fourth Quarter (in millions) 2016 Operating Revenue $ 243 $ 317 $ 394 $ 281 Operating Income 12 72 122 37 Net Income (Loss) (1 ) 41 72 12 2015 Operating Revenue $ 273 $ 340 $ 409 $ 284 Operating Income 28 74 120 36 Net Income 9 38 69 12

NATURE OF OPERATIONS AND SUMM23

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis Of Presentation	BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with GAAP in the United States, including specific accounting guidance for regulated operations. See Note 2 for additional information regarding regulatory matters. The 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 Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included in the Consolidated Statements of Income. See Note 3 for additional information regarding Utility Plant. Certain amounts from prior periods have been reclassified to conform to the current year presentation.
Variable Interest Entity	Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP routinely enters into long-term PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary 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 December 31, 2016 , the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to its variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent 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.
Recently Adopted Accounting Pronouncements	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS Effective January 1, 2016 , TEP adopted accounting guidance that simplifies the accounting for share-based payment accounting. The guidance requires that excess tax benefits and tax deficiencies be recorded as income tax benefit or expense on the statement of income and eliminates the requirement that excess tax benefits be realized before companies can recognize them. On adoption, using the modified retrospective method of transition, TEP recorded a cumulative effect adjustment of $10 million to increase retained earnings and decrease deferred income taxes related to prior period unrecognized excess tax benefits. The impact on the income statement and the statement of cash flows were not significant. TEP elected to recognize forfeitures when they occur.
Use of Accounting Estimates	USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheets at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statements during the periods presented. Because these estimates involve judgments based upon the Company's evaluation of relevant facts and circumstances, actual results may differ from these estimates.
Asset Retirement Obligations	Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its PV assets as a result of entering into various ground leases or easement agreements. The Company records a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income and the capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers costs associated with its legal AROs as regulatory assets based on the ACC approval of these costs in TEP's depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in the rates charged to retail customers and an obligation is recorded for estimated costs of removal as regulatory liabilities.
Contingencies	Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
Accounting for Regulated Operations	ACCOUNTING FOR REGULATED OPERATIONS TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through future rate reductions. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets each period and believes recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.
Cash and Cash Equivalents	CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
Restricted Cash	RESTRICTED CASH Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property on the balance sheets. Restricted cash was $7 million and $4 million as of December 31, 2016 and 2015 , respectively.
Allowance for Doubtful Accounts	ALLOWANCE FOR DOUBTFUL ACCOUNTS TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Company's Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2016 2015 2014 Beginning of Period $ 27 $ 5 $ 5 Additions Charged to Cost and Expense 4 2 2 Write-offs (3 ) (3 ) (2 ) Provision for Springerville Unit 1, Third-Party Owners (23 ) 23 — End of Period $ 5 $ 27 $ 5 The allowance for doubtful accounts decreased in 2016 due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims.
Inventory	INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost or market. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in Retail Rates. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.
Utility Plant	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 (AFUDC), less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no income statement impact.
AFUDC and Capitalized Interest	AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Other Income on the Consolidated Statements of Income. The average AFUDC rates on regulated construction expenditures are included in the table below: 2016 2015 2014 Average AFUDC Rates 7.47 % 6.12 % 7.30 %
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. See Note 3 for additional information regarding Utility Plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant: 2016 2015 2014 Average Annual Depreciation Rates 2.85 % 2.83 % 2.99 %
Utility Plant Under Capital Leases	Utility Plant Under Capital Leases TEP finances the Springerville Common Facilities with capital leases. The capital lease expense incurred consists of Amortization Expense and Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 for additional information regarding Utility Plant and Note 6 for additional information related to the lease terms.
Computer Software Costs	Computer Software Costs Costs incurred to purchase and develop internal use computer software are capitalized and those costs are amortized over the estimated economic life of the product. If the software is no longer useful or impaired, the carrying value is reduced and charged to expense.
Evaluation of Assets for Impairment	EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates
Deferred Financing Costs	DEFERRED FINANCING COSTS Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt, as this approximates the effective interest method. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to line-of-credit arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt.
Operating Revenues	OPERATING REVENUES Revenues related to the sale of energy are recognized when services or commodities are delivered to customers. The billing of electric sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates. For purchased power and wholesale revenue contracts that are settled financially, TEP nets the revenue contracts with the purchased power contracts and reflects the amount in Wholesale Revenues on the Consolidated Statements of Income. TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned. The ACC has authorized mechanisms for LFCR mechanism related to kWh sales lost due to EE Standards and distributed generation. Revenues are recognized in the period that verifiable energy savings occur. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected.
Purchased Power and Fuel Adjustment Clause	PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE TEP recovers actual fuel, purchased power and transmission costs through base fuel rates and a PPFAC to provide electric service to retail customers. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters.
Renewable Energy and Energy Efficiency Programs and Renewable Energy Credits	RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s 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 in 2025 , with distributed generation 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. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge until such costs are reflected in TEP's non-fuel base rates. TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020 . Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP recognizes RES and DSM surcharge revenue in Retail Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC. When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. TEP had $24 million and $8 million of RECs as of December 31, 2016 and 2015 , respectively. RECs are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 for additional information regarding regulatory matters.
Income Taxes	INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense on the Consolidated Statements of Income. Prior to 1990, TEP flowed through to customers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory assets include income taxes recoverable through future rates, which reflects the future revenues due to TEP from customers as these tax benefits reverse. See Note 2 for additional information regarding regulatory matters. TEP accounts for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income ax expense in the year the credit arises.
Taxes Other Than Income Taxes	TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statements.
Fair Value	FAIR VALUE As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 11 for additional information regarding fair value.
Derivative Instruments	DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to meet forecasted load and reserve requirements, to reduce exposure to energy commodity price volatility and to hedge interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, those derivative instruments are recognized as either assets or liabilities on the Consolidated Balance Sheets and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Income. For derivatives designated as hedging contracts, TEP formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy. For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 11 for additional information regarding derivative instruments.
Pension and Other Retiree Benefits	PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited health care and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects to recover these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 8 for additional information regarding the employee benefit plans.

NATURE OF OPERATIONS AND SUMM24

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance For Doubtful Accounts	The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Company's Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2016 2015 2014 Beginning of Period $ 27 $ 5 $ 5 Additions Charged to Cost and Expense 4 2 2 Write-offs (3 ) (3 ) (2 ) Provision for Springerville Unit 1, Third-Party Owners (23 ) 23 — End of Period $ 5 $ 27 $ 5
AFUDC Rates	The average AFUDC rates on regulated construction expenditures are included in the table below: 2016 2015 2014 Average AFUDC Rates 7.47 % 6.12 % 7.30 %
Summary Of Average Annual Depreciation Rates For All Utility Plants	Below are the summarized average annual depreciation rates for all utility plant: 2016 2015 2014 Average Annual Depreciation Rates 2.85 % 2.83 % 2.99 %

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2016
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 October 2014 through March 2015 0.50 May 2014 through September 2014 0.10 July 2013 through April 2014 (0.14 )
Schedule of Regulatory Assets and Liabilities	The regulatory assets and liabilities recorded in the Consolidated Balance Sheets are summarized in the table below: Remaining Recovery Period (years) December 31, (dollars in millions) 2016 2015 Regulatory Assets Pension and Other Postretirement Benefits (Note 8) Various $ 128 $ 120 Income Taxes Recoverable through Future Rates (1) Various 29 26 Final Mine Reclamation and Retiree Health Care Costs (2) 21 27 28 Property Tax Deferrals (3) 1 23 21 Lost Fixed Cost Recovery 1 23 16 Springerville Unit 1 Leasehold Improvements (4) 7 17 21 Sundt Coal Handling Facilities (5) Plant Life 16 — Derivatives (Note 11) 3 2 12 Other Regulatory Assets Various 16 20 Total Regulatory Assets 281 264 Less Current Portion 1 56 52 Total Non-Current Regulatory Assets $ 225 $ 212 Regulatory Liabilities Net Cost of Removal for Interim Retirements (6) Various $ 270 $ 264 Purchased Power and Fuel Adjustment Clause 1 38 18 Renewable Energy Standard Various 32 25 Deferred Investment Tax Credits (7) Various 23 32 Other Regulatory Liabilities Various 14 21 Total Regulatory Liabilities 377 360 Less Current Portion 1 76 53 Total Non-Current Regulatory Liabilities $ 301 $ 307 (1) Income Taxes Recoverable through Future Rates are amortized over the life of the assets. See Note 1 and Note 12 for additional information regarding income taxes. (2) Final Mine Reclamation and Retiree Health Care Costs represent costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC when paid. The majority of the final mine reclamation costs are expected to occur through 2037 . (3) Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities to recover property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. (4) Springerville Unit 1 Leasehold Improvements represent investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year amortization period. (5) In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP will apply excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. (6) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future AROs net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. (7) Accumulated Deferred Investment Tax Credits (ITC) represent federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

UTILITY PLANT AND JOINTLY-OWN26

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Public Utility Property, Plant, and Equipment	The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (4) Average Remaining Life in Years (4) December 31, (dollars in millions) 2016 2015 Plant in Service Generation Plant 3.31% 22 $ 2,866 $ 2,612 Transmission Plant 1.48% 32 1,024 1,008 Distribution Plant 2.08% 35 1,512 1,456 General Plant 5.48% 11 381 358 Intangible Plant, Software Costs and Other (1) Various Various 185 179 Plant Held for Future Use — — 7 5 Total Plant in Service (2) $ 5,975 $ 5,618 Utility Plant under Capital Leases (3) $ 167 $ 132 (1) Unamortized computer software costs were $52 million and $45 million as of December 31, 2016 and 2015 , respectively. The amortization of computer software costs were $17 million in 2016 , $14 million in 2015 , and $17 million in 2014 . Intangible Plant, Software Costs and Other primarily represents computer software. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and its average remaining life of three years for large enterprise software . (2) Included in Plant in Service are plant acquisition adjustments of $(139) million and $(97) million as of December 31, 2016 and 2015 , respectively. (3) In 2016 , TEP committed to purchase an undivided ownership interest in the Springerville Common Facilities upon the expiration of the first lease term in December 2017. As a result of this commitment, Utility Plant Under Capital Leases increased by the present value of the purchase commitment. See Note 6 for additional information regarding the Springerville leases. (4) The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant. Annual Depreciation Rate and Average Remaining Life in Years are based on the 2012 depreciation study available for the major classes of Plant in Service. TEP will implement new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order.
Amount Of Lease Expense Incurred Related Capital Leases	The following table shows the amount of lease expense incurred for capital leases: Years Ended December 31, (in millions) 2016 2015 2014 Lease Expense Interest Expense Included in: Interest Expense, Capital Leases $ 3 $ 4 $ 10 Operating Expenses, Fuel — — 1 Amortization of Capital Lease Assets Included in: Operating Expenses, Fuel — 2 6 Operating Expenses, Amortization 5 6 16 Total Lease Expense $ 8 $ 12 $ 33
Schedule of Jointly Owned Utility Plants	As of December 31, 2016 , TEP was a participant in the following jointly-owned generation facilities and transmission systems: (in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Units 1 and 2 50.0% $ 496 $ 3 $ 262 $ 237 Navajo Units 1, 2, and 3 7.5% 149 4 114 39 Four Corners Units 4 and 5 7.0% 110 27 76 61 Luna Energy Facility 33.3% 55 — 2 53 Gila River Unit 3 75.0% 202 3 59 146 Gila River Common Facilities 18.8% 25 — 8 17 Springerville Coal Handling Facility (1) 83.0% 201 — 80 121 Transmission Facilities Various 383 3 175 211 Total $ 1,621 $ 40 $ 776 $ 885 (1) As of December 31, 2015, an undivided interest in Springerville Coal Handling Facilities was classified as Assets Held for Sale, Net. In 2016, TEP reclassified the undivided interest in the Springerville Coal Handling Facilities from Assets Held for Sale, Net to Utility Plant on the Consolidated Balance Sheets. See Note 6 for additional information regarding the Springerville Coal Handling Facilities lease interests.
Schedule of Asset Retirement Obligations	The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals in the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Beginning of Period $ 32 $ 28 Liabilities Incurred — 4 Accretion Expense or Regulatory Deferral 2 1 Revisions to the Present Value of Estimated Cash Flows (1) (1 ) (1 ) End of Period $ 33 $ 32 (1) Primarily related to changes in expected cost estimates, in conjunction with changes of asset retirement dates of generation facilities.

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2016
Accounts Receivable, Net [Abstract]
Accounts Receivable	The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Customer $ 74 $ 79 Due from Affiliates (Note 5) 9 7 Unbilled 34 39 Other (1) 13 39 Allowance for Doubtful Accounts (1) (5 ) (27 ) Accounts Receivable, Net $ 125 $ 137 (1) In 2016, Accounts Receivable—Other and Allowance for Doubtful Accounts decreased due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Table)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Receivables from Related Parties UNS Electric $ 7 $ 6 UNS Gas 2 1 Total Due from Related Parties $ 9 $ 7 Payables to Related Parties SES $ 2 $ 2 UNS Electric — 2 UNS Energy — 2 Total Due to Related Parties $ 2 $ 6 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2016 2015 2014 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 7 $ 6 $ 1 Wholesale Revenues, UNS Electric (1) — 2 3 Control Area Services, UNS Electric (2) 2 2 3 Common Costs, UNS Energy Affiliates (3) 14 12 13 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) 1 1 4 Supplemental Workforce, SES (4) 14 16 16 Corporate Services, UNS Energy (5) 7 7 14 Corporate Services, UNS Energy Affiliates (6) 4 1 1 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates through the applicable Open Access Transmission Tariff. (2) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (4) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (5) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal and audit fees. Beginning in 2015, following the August 2014 Fortis acquisition, it includes Fortis management fees of approximately $6 million in 2016 and $5 million in 2015 . (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.

DEBT, CREDIT FACILITY, AND CA29

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	DEBT Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, (dollars in millions) Interest Rate Maturity Date 2016 2015 Notes 2011 Notes 5.15% 2021 $ 250 $ 250 2012 Notes 3.85% 2023 150 150 2014 Notes 5.00% 2044 150 150 2015 Notes 3.05% 2025 300 300 Tax-Exempt Local Furnishings Bonds 2010 Pima A 5.25% 2040 100 100 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 2013 Apache A (1) 1.01% 2032 100 100 Tax-Exempt Pollution Control Bonds 2009 Pima A 4.95% 2020 80 80 2009 Coconino A 5.13% 2032 15 15 2010 Coconino A (2) 1.33% 2032 37 37 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt (3) 1,466 1,466 Less Unamortized Discount and Debt Issuance Costs 13 14 Total Long-Term Debt, Net $ 1,453 $ 1,452 (1) The bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average based on a percentage of an index equal to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in 2018. (2) The bonds are variable rate debt for which rates are reset weekly. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. (3) As of December 31, 2016 , all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by a LOC.
Schedule of Capital Lease Obligations [Table Text Block]	CAPITAL LEASE OBLIGATIONS The following table details Capital Lease Obligations on the Consolidated Balance Sheets: December 31, (in millions) 2016 2015 Capital Lease Obligations $ 91 $ 69 Less Current Obligations Under Capital Leases 52 14 Total Capital Lease Obligations, Non-Current $ 39 $ 55
Schedule of Maturities of Long-term Debt [Table Text Block]	DEBT MATURITIES Long-term debt, including revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: (in millions) Long-Term Debt (1) Capital Lease Obligations Total Debt Maturities (2) 2017 $ — $ 52 $ 52 2018 100 11 111 2019 37 11 48 2020 80 18 98 2021 250 — 250 Total 2017 - 2021 467 92 559 Thereafter 999 — 999 Less: Imputed Interest — (1 ) (1 ) Total $ 1,466 $ 91 $ 1,557 (1) $37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in 2018. (2) Total long-term debt excludes $10 million of related unamortized debt issuance costs and $3 million of unamortized original issue discount.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments	As of December 31, 2016 , TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases: (in millions) 2017 2018 2019 2020 2021 Thereafter Total Fuel, Including Transportation $ 100 $ 76 $ 76 $ 67 $ 43 $ 269 $ 631 Purchased Power 32 — — — — — 32 Transmission 18 19 19 8 4 10 78 Renewable Power Purchase Agreements 64 64 64 63 63 730 1,048 RES Performance-Based Incentives 8 8 8 8 8 59 99 Operating Leases: Land Easements and Rights-of-Way 1 1 1 1 2 75 81 Other 1 1 1 1 1 4 9 Total Purchase Commitments $ 224 $ 169 $ 169 $ 148 $ 121 $ 1,147 $ 1,978

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Schedule of Amounts Recognized in Balance Sheet	The following table summarizes pension and other postretirement benefit amounts (excluding tax balances) included in the Consolidated Balance Sheets: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2016 2015 2016 2015 Regulatory Assets $ 123 $ 115 $ 5 $ 5 Accrued Employee Expenses (1 ) (1 ) (2 ) (2 ) Pension and Other Postretirement Benefits (69 ) (57 ) (63 ) (63 ) Accumulated Other Comprehensive Loss, SERP 6 5 — — Net Amount Recognized $ 59 $ 62 $ (60 ) $ (60 )
Schedule of Changes in Funded Status	All plans have projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2016 2015 2016 2015 Change in Projected Benefit Obligation Beginning of Period $ 394 $ 407 $ 78 $ 81 Actuarial (Gain) Loss 20 (22 ) — (5 ) Interest Cost 15 17 2 3 Service Cost 12 12 4 4 Benefits Paid (17 ) (20 ) (5 ) (5 ) End of Period 424 394 79 78 Change in Fair Value of Plan Assets Beginning of Period 336 335 13 12 Actual Return on Plan Assets 27 (3 ) 1 — Benefits Paid (17 ) (20 ) (5 ) (5 ) Employer Contributions (1) 8 24 5 6 End of Period 354 336 14 13 Funded Status at End of Period $ (70 ) $ (58 ) $ (65 ) $ (65 ) (1) TEP expects to contribute $11 million to the pension plans in 2017 .
Schedule of Net Periodic Benefit Cost Not yet Recognized	The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2016 2015 2016 2015 Net Loss $ 128 $ 117 $ 6 $ 6 Prior Service Cost (Benefit) — 3 (1 ) (1 )
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	The following table includes information for pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2016 2015 Accumulated Benefit Obligation $ 384 $ 188 Fair Value of Plan Assets 354 169
Components of Net Periodic Benefit Cost	Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2016 2015 2014 2016 2015 2014 Service Cost $ 12 $ 12 $ 10 $ 4 $ 4 $ 4 Interest Cost 15 17 16 2 3 3 Expected Return on Plan Assets (23 ) (23 ) (21 ) (1 ) (1 ) (1 ) Amortization of Net Loss 7 7 3 — — — Net Periodic Benefit Cost $ 11 $ 13 $ 8 $ 5 $ 6 $ 6 Approximately 19% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)	The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Current Year Actuarial (Gain) Loss $ 15 $ 5 $ 49 $ 1 $ — $ 3 $ — $ (4 ) $ 5 Amortization of Net Loss (7 ) (7 ) (3 ) — — — — — — Total Recognized (Gain) Loss $ 8 $ (2 ) $ 46 $ 1 $ — $ 3 $ — $ (4 ) $ 5
Schedule of Expected Amortization of Prior Service Costs Charged to Net Period Benefit Cost	For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. Estimated amortization from regulatory assets into net periodic benefit cost in 2017 includes the following: (in millions) Pension Benefits Other Postretirement Benefits Net Loss $ 7 $ —
Schedule Of Weighted Average Assumptions Used To Determine Benefit Obligations At Year End Table	The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Discount Rate 4.2% 4.5% 4.0% 4.2% Rate of Compensation Increase 2.8% 3.0% N/A N/A
Schedule Of Weighted Average Assumptions Used To Determine Net Periodic Benefit Cost Table	The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount Rate, Service Cost 4.8% 4.2% 5.1% 4.6% 3.9% 4.7% Discount Rate, Interest Cost 3.9% 4.2% 5.1% 3.4% 3.9% 4.7% Rate of Compensation Increase 3.0% 3.0% 3.0% N/A N/A N/A Expected Return on Plan Assets 7.0% 7.0% 7.0% 7.0% 7.0% 7.0%
Schedule of Health Care Cost Trend Rates	The following table includes the assumed health care cost trend rates: December 31, 2016 2015 Next Year 7.6% 7.6% Ultimate Rate Assumed 4.5% 4.5% Year Ultimate Rate is Reached 2037 2036
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the amounts: One-Percentage- Point Increase One-Percentage- Point Decrease (in millions) December 31, 2016 Increase (Decrease) on Total Service and Interest Cost Components $ 1 $ (1 ) Increase (Decrease) on Other Postretirement Benefit Obligation 7 (6 )
Schedule of Allocation of Plan Assets	Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement 2016 2015 2016 2015 Asset Category Equity Securities 49 % 49 % 60 % 60 % Fixed Income Securities 41 % 41 % 35 % 35 % Real Estate 8 % 8 % 2 % 2 % Other 2 % 2 % 3 % 3 % Total 100 % 100 % 100 % 100 %
FV Measurements of Pension Plan Assets by FV Hierarchy	The following table sets forth the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2016 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 61 — 61 United States Small Cap — 18 — 18 Non-United States — 67 — 67 Global — 28 — 28 Fixed Income — 144 — 144 Real Estate — 9 19 28 Private Equity — — 7 7 Total $ 1 $ 327 $ 26 $ 354 (in millions) December 31, 2015 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 81 — 81 United States Small Cap — 17 — 17 Non-United States — 67 — 67 Fixed Income — 137 — 137 Real Estate — 8 18 26 Private Equity — — 7 7 Total $ 1 $ 310 $ 25 $ 336 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 100% of real estate assets tracked by the index. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
Schedule of Reconciliation of Changes in Fair Value of Level 3 Plan Assets	The following table sets forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2014 $ 7 $ 16 $ 23 Actual Return on Plan Assets: Assets Held at Reporting Date 1 2 3 Purchases, Sales, and Settlements (1 ) — (1 ) Balance as of December 31, 2015 7 18 25 Actual Return on Plan Assets: Assets Held at Reporting Date 1 1 2 Purchases, Sales, and Settlements (1 ) — (1 ) Balance as of December 31, 2016 $ 7 $ 19 $ 26
Target Allocation Percentages for Plan Assets	The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. Pension Other Postretirement December 31, 2016 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 17% 39% United States Small Cap 5% 5% Non-United States Developed 15% 7% Non-United States Emerging 4% 9% Global Equity 5% —% Global Infrastructure 3% —% Fixed Income 42% 38% Real Estate 8% —% Private Equity 1% —% Total 100% 100%
Schedule of Expected Benefit Payments	TEP expects the following benefit payments to be made by the defined benefit pension plans and other postretirement benefit plan, which reflect future service, as appropriate. (in millions) 2017 2018 2019 2020 2021 2022-2026 Pension Benefits $ 18 $ 19 $ 20 $ 22 $ 23 $ 128 Other Postretirement Benefits 4 5 5 6 6 32

SHARE-BASED COMPENSATION (Table

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	UNS Energy awarded PSUs and RSUs as follows: 2016 2015 PSUs 66,974 47,776 RSUs 33,488 23,888

SUPPLEMENTAL CASH FLOW (Tables)

SUPPLEMENTAL CASH FLOW (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	CASH TRANSACTIONS Years Ended December 31, (in millions) 2016 2015 2014 Interest, Net of Amounts Capitalized $ 61 $ 65 $ 83 Income Taxes — — — 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: Years Ended December 31, (in millions) 2016 2015 2014 Accrued Capital Expenditures $ 29 $ 28 $ 29 Net Cost of Removal of Interim Retirements (1) 8 1 12 Commitment to Purchase Capital Lease Interests 36 — 109 Capital Lease Obligations (2) — — 1 Asset Retirement Obligations (3) (1 ) 3 4 (1) The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings. (2) The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments. (3) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future AROs.

FAIR VALUE MEASUREMENTS AND D34

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block [Abstract]
Financial Instruments Measured at Fair Value on a Recurring Basis	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) 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 ) Net Total Assets (Liabilities) $ 30 $ (1 ) $ 1 $ 30 (in millions) December 31, 2015 Assets Cash Equivalents (1) $ 33 $ — $ — $ 33 Restricted Cash (1) 4 — — 4 Energy Derivative Contracts, Regulatory Recovery (2) — 1 — 1 Energy Derivative Contracts, No Regulatory Recovery (2) — — 1 1 Total Assets 37 1 1 39 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (10 ) (3 ) (13 ) Interest Rate Swap (3) — (3 ) — (3 ) Total Liabilities — (13 ) (3 ) (16 ) Net Total Assets (Liabilities) $ 37 $ (12 ) $ (2 ) $ 23 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds 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 Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property on the Consolidated Balance Sheets. (2) Energy Contracts include gas swap agreements (Level 2), gas options (Level 3), 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 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 LIBOR and is included in Derivative Instruments on the 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) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) (in millions) December 31, 2015 Derivative Assets Energy Derivative Contracts $ 2 $ 1 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (13 ) (1 ) — (12 ) Interest Rate Swap (3 ) — — (3 )
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) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) (in millions) December 31, 2015 Derivative Assets Energy Derivative Contracts $ 2 $ 1 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (13 ) (1 ) — (12 ) Interest Rate Swap (3 ) — — (3 )
Realized Losses from Cash Flow Hedges	Realized losses from cash flow hedges are shown in the following table: Years Ended December 31, (in millions) 2016 2015 2014 Capital Lease Interest Expense $ 1 $ 2 $ 2 Long-Term Debt Interest Expense — — 1 Purchased Power — 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 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 following table: Years Ended December 31, (in millions) 2016 2015 2014 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ 12 $ 6 $ (18 )
Derivative Volumes	Derivative Volumes As of December 31, 2016 , TEP has energy contracts that will settle through 2019 . The volumes associated with the energy contracts were as follows: December 31, 2016 2015 Power Contracts GWh 2,610 1,752 Gas Contracts BBtu 12,355 17,214
Fair Value Inputs, Assets, Quantitative Information Regarding Significant Unobservable Inputs	Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 Level 3 Energy Contracts $ 2 $ (1 ) (in millions) December 31, 2015 Forward Power Contracts Market approach $ 1 $ (2 ) Market price per MWh $ 19.20 $ 31.35 Gas Option Contracts Option model — (1 ) Market price per MMbtu $ 2.17 $ 2.69 Gas volatility 31.0% 58.3% Level 3 Energy Contracts $ 1 $ (3 )
Fair Value Inputs, Liabilities, Quantitative Information Regarding Significant Unobservable Inputs	Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 Level 3 Energy Contracts $ 2 $ (1 ) (in millions) December 31, 2015 Forward Power Contracts Market approach $ 1 $ (2 ) Market price per MWh $ 19.20 $ 31.35 Gas Option Contracts Option model — (1 ) Market price per MMbtu $ 2.17 $ 2.69 Gas volatility 31.0% 58.3% Level 3 Energy Contracts $ 1 $ (3 )
Level 3 Fair Value Reconciliation of Changes	The following table presents a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy: Years Ended December 31, (in millions) 2016 2015 Beginning of Period $ (2 ) $ (9 ) Gains (Losses) Recorded (1) Net Regulatory Assets or Liabilities, Derivative Instruments 2 (4 ) Electric Wholesale Sales 4 3 Settlements (3 ) 8 End of Period $ 1 $ (2 ) (1) Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $1 million and $(1) million for the years ended December 31, 2016 and 2015 , respectively.
Face Value and Estimated Fair Value of Long-Term Debt	The following table includes the face value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Face Value Fair Value December 31, (in millions) 2016 2015 2016 2015 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,472 $ 1,529

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following: Years Ended December 31, (in millions) 2016 2015 2014 Federal Income Tax Expense at Statutory Rate $ 64 $ 70 $ 56 State Income Tax Expense, Net of Federal Deduction 6 8 7 Federal/State Tax Credits (8 ) (8 ) (5 ) Allowance for Equity Funds Used During Construction (1 ) (1 ) (2 ) Deferred Tax Asset Valuation Allowance (2 ) 1 — Other — 2 2 Total Federal and State Income Tax Expense $ 59 $ 72 $ 58
Schedule Of Income Tax Reconciliation Table	Income tax expense included in the income statements consists of the following: Years Ended December 31, (in millions) 2016 2015 2014 Current Tax Expense (Benefit) Federal $ — $ — $ (1 ) State — — — Total Current Tax Expense (Benefit) — — (1 ) Deferred Tax Expense (Benefit) Federal 60 66 54 Federal Investment Tax Credits (6 ) (6 ) (4 ) State 5 12 9 Total Deferred Tax Expense (Benefit) 59 72 59 Total Federal and State Income Tax Expense $ 59 $ 72 $ 58
Schedule of Deferred Tax Assets and Liabilities	The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2016 2015 Gross Deferred Income Tax Assets Capital Lease Obligations $ 35 $ 27 Net Operating Loss Carryforwards 129 156 Customer Advances and Contributions in Aid of Construction 20 20 Alternative Minimum Tax Credit 25 24 Accrued Postretirement Benefits 23 23 Emission Allowance Inventory 9 9 Investment Tax Credit Carryforward 32 32 Other 60 53 Total Gross Deferred Income Tax Assets 333 344 Deferred Tax Assets Valuation Allowance — (4 ) Gross Deferred Income Tax Liabilities Plant, Net (774 ) (750 ) Capital Lease Assets, Net (24 ) (12 ) Pensions (26 ) (27 ) Other (38 ) (19 ) Total Gross Deferred Income Tax Liabilities (862 ) (808 ) Net Deferred Income Tax Liabilities $ 529 $ 468
Summary Of Details Of Tax Carryforwards Table	As of December 31, 2016 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 364 2031-34 State Credits 10 2017-29 Alternative Minimum Tax Credit 25 None Investment Tax Credits 32 2032-36
Summary of Income Tax Contingencies	A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2016 2015 Beginning of Period $ 5 $ 4 Additions Based on Tax Positions Taken in the Current Year 7 1 End of Period $ 12 $ 5

QUARTERLY FINANCIAL DATA (UNAU

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. First Quarter Second Quarter Third Quarter Fourth Quarter (in millions) 2016 Operating Revenue $ 243 $ 317 $ 394 $ 281 Operating Income 12 72 122 37 Net Income (Loss) (1 ) 41 72 12 2015 Operating Revenue $ 273 $ 340 $ 409 $ 284 Operating Income 28 74 120 36 Net Income 9 38 69 12

NATURE OF OPERATIONS AND SUMM37

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Details) customer in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)mi²customer	Dec. 31, 2015USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Retail customers | customer	420
Area in which subsidiary generates transmits and distributes electricity to retail electric customers | mi²	1,155
Restricted Cash and Cash Equivalents, Noncurrent | $	$ 7	$ 4

NATURE OF OPERATIONS AND SUMM38

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Recently Adopted Accounting Pronouncements) (Details) $ in Thousands	Dec. 31, 2016USD ($)
Retained Earnings [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 9,653
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standard Update 2016-09 [Member] | Deferred Income Taxes Current And Noncurrent [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	10,000
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standard Update 2016-09 [Member] | Retained Earnings [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 10,000

NATURE OF OPERATIONS AND SUMM39

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Allowance for Doubtful Accounts) (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning of Period	$ 27	$ 5	$ 5
Additions Charged to Cost and Expense	4	2	2
Write-offs	(3)	(3)	(2)
End of Period	5	27	5
Springerville Unit 1 Third Party Owner Allegation [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Adjustments	$ (23)	$ 23	$ 0

NATURE OF OPERATIONS AND SUMM40

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average AFUDC Rates	7.47%	6.12%	7.30%

NATURE OF OPERATIONS AND SUMM41

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average Annual Depreciation Rates	2.85%	2.83%	2.99%

NATURE OF OPERATIONS AND SUMM42

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy and Energy Efficiency Programs) (Details)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2020	Dec. 31, 2016
Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage by 2025			6.00%
Scenario, Forecast [Member] | Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage by 2025	15.00%
Distributed Generation Requirement Target Percentage	30.00%
Scenario, Forecast [Member] | Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Percentage of Electric Energy Efficiency Standards Target Retail Savings on Sales by 2020		22.00%

NATURE OF OPERATIONS AND SUMM43

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy Credits) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Renewable Energy Credits	$ 24	$ 8

REGULATORY MATTERS (2017 Rate O

REGULATORY MATTERS (2017 Rate Order) (Details) - Arizona Corporation Commission [Member] - USD ($) $ in Millions	1 Months Ended
	Feb. 28, 2017	Sep. 30, 2016
Subsequent Event [Member]
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%
Subsequent Event [Member] | Non-fuel Component of Base Rate [Member]
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase over adjusted test year revenues	$ 81.5
Springerville Unit One [Member]
Public Utilities, General Disclosures [Line Items]
Purchased undivided interest in Springerville Unit 1		50.50%
Springerville Unit One [Member] | Subsequent Event [Member] | Non-fuel Component of Base Rate [Member]
Public Utilities, General Disclosures [Line Items]
Unit 1 Operating costs included in base rate increase	$ 15

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) $ in Millions	1 Months Ended			12 Months Ended
	Feb. 28, 2017$ / kWh	May 31, 2016USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2025	Dec. 31, 2020	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)$ / kWh	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
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							$ 38	$ 18
Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage							6.00%
Approved Spending Budget		$ 57
Approved Carryover of Unused Funds		9
Approved Recovery of Spending Budget		$ 48
Recovery Revenue							$ 3
Renewable Energy Actual Percentage							10.00%
Renewable Energy Program [Member] | Scenario, Forecast [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage				15.00%
Distributed Generation Requirement Target Percentage				30.00%
Recovery Revenue						$ 1
Renewable Energy Budget Spending						$ 54
Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Approved Recovery of Spending Budget			$ 14
Percentage of Cumulative Annual Retail Kilowatt Savings, Actual							12.00%
Energy Efficiency Standards [Member] | Scenario, Forecast [Member]
Public Utilities, General Disclosures [Line Items]
Percentage of Electric Energy Efficiency Standards Target Retail Savings on Sales					22.00%
Demand Side Management - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue							$ 2	3	$ 2
Lost Fixed Cost Recovery Mechanism - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue							$ 18	$ 12	$ 11
Cap on Increase in Lost Fixed Cost Recovery Rate							1.00%
Effective May 2016 through February 2017 [Member] | Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / kWh							0.0015
Effective April 2015 through March 2016 [Member] | Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / kWh							0.0068
Effective October 2014 through March 2015 [Member] | Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / kWh							0.0050
Effective May 2014 through September 2014 [Member] | Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / kWh							0.0010
Effective July 2013 through April 2014 [Member] | Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / kWh							(0.0014)
Subsequent Event [Member] | Effective March 2017 through March 2018 [Member] | Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / kWh	(0.0020)

REGULATORY MATTERS (FERC Compli

REGULATORY MATTERS (FERC Compliance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
FERC Refund Orders [Member]
Public Utilities, General Disclosures [Line Items]
Transmission Service Agreement time value refunds recorded	$ 22

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Assets	$ 281,000	$ 264,000
Regulatory Assets, Current	56,340	51,841
Regulatory Assets, Noncurrent	225,453	212,312
Pension and Other Postretirement Benefits (Note 8)
Regulatory Assets [Line Items]
Regulatory Assets	128,000	120,000
Income Taxes Recoverable through Future Rates (1)
Regulatory Assets [Line Items]
Regulatory Assets	$ 29,000	26,000
Final Mine Reclamation and Retiree Health Care Costs (2)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	21 years
Regulatory Assets	$ 27,000	28,000
Property Tax Deferrals (3)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	6 months
Regulatory Assets	$ 23,000	21,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Assets	$ 23,000	16,000
Springerville Unit 1 Leasehold Improvements (4)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	7 years
Regulatory Assets	$ 17,000	21,000
Amortization period authorized to recover leasehold improvement costs at Springerville Unit 1	10 years
Sundt Coal Handling Facilities (5)
Regulatory Assets [Line Items]
Regulatory Assets	$ 16,000	0
Derivatives (Note 11)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	3 years
Regulatory Assets	$ 2,000	12,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Assets	$ 16,000	$ 20,000

REGULATORY MATTERS (Regulator48

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Liabilities	$ 377,000	$ 360,000
Regulatory Liabilities, Current	76,069	53,077
Regulatory Liabilities, Noncurrent	300,700	307,286
Net Cost of Removal for Interim Retirements (6)
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 270,000	264,000
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Regulatory Liabilities	$ 38,000	18,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Regulatory Liabilities	32,000	25,000
Deferred Investment Tax Credits (7)
Regulatory Liabilities [Line Items]
Regulatory Liabilities	23,000	32,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 14,000	$ 21,000

UTILITY PLANT AND JOINTLY-OWN49

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Major Class) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.85%	2.83%	2.99%
Total Plant in Service	$ 5,975,139	$ 5,618,435
Utility Plant Under Capital Leases	167,413	131,705
Plant Acquisition Adjustments	$ (139,000)	(97,000)
Generation Plant
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	3.31%
Average Remaining Life of Public Utilities Property Plant and Equipment	22 years
Total Plant in Service	$ 2,866,000	2,612,000
Transmission Plant
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	1.48%
Average Remaining Life of Public Utilities Property Plant and Equipment	32 years
Total Plant in Service	$ 1,024,000	1,008,000
Distribution Plant
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.08%
Average Remaining Life of Public Utilities Property Plant and Equipment	35 years
Total Plant in Service	$ 1,512,000	1,456,000
General Plant
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	5.48%
Average Remaining Life of Public Utilities Property Plant and Equipment	11 years
Total Plant in Service	$ 381,000	358,000
Intangible Plant, Software Costs and Other (1)
Public Utility, Property, Plant and Equipment [Line Items]
Total Plant in Service	185,000	179,000
Capitalized Computer Software, Net	52,000	45,000
Amortization of computer software costs	17,000	14,000	$ 17,000
Plant Held for Future Use
Public Utility, Property, Plant and Equipment [Line Items]
Total Plant in Service	$ 7,000	$ 5,000
Enterprise Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Average Remaining Life of Public Utilities Property Plant and Equipment	3 years
Minimum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	3 years
Maximum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	5 years

UTILITY PLANT AND JOINTLY-OWN50

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for Generation-Related Capital Leases) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Capital Lease Expense	$ 8	$ 12	$ 33
Interest Expense, Capital Leases
Public Utility, Property, Plant and Equipment [Line Items]
Interest Expense	3	4	10
Operating Expenses, Fuel
Public Utility, Property, Plant and Equipment [Line Items]
Interest Expense	0	0	1
Amortization of Capital Lease Assets	0	2	6
Operating Expenses, Amortization
Public Utility, Property, Plant and Equipment [Line Items]
Amortization of Capital Lease Assets	$ 5	$ 6	$ 16

UTILITY PLANT AND JOINTLY-OWN51

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Springerville Acquisition) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Unusual or Infrequent Item [Line Items]
Payments to Acquire Other Productive Assets		$ 85,000	$ 45,753	$ 19,608
Settled Litigation [Member] | Springerville Unit 1 Third Party Owner Allegation [Member]
Unusual or Infrequent Item [Line Items]
Payments to Acquire Other Productive Assets	$ 85,000
Percentage Of Ownership In Generating Units	100.00%

UTILITY PLANT AND JOINTLY-OWN52

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Jointly-Owned Facilities) (Details) $ in Millions	Dec. 31, 2016USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$ 1,621
Construction Work in Progress	40
Accumulated Depreciation	776
Net Book Value	$ 885
San Juan Units 1 and 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Plant in Service	$ 496
Construction Work in Progress	3
Accumulated Depreciation	262
Net Book Value	$ 237
Navajo Units 1, 2, and 3 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	7.50%
Plant in Service	$ 149
Construction Work in Progress	4
Accumulated Depreciation	114
Net Book Value	$ 39
Four Corners Units 4 and 5 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	7.00%
Plant in Service	$ 110
Construction Work in Progress	27
Accumulated Depreciation	76
Net Book Value	$ 61
Luna Energy Facility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	33.30%
Plant in Service	$ 55
Construction Work in Progress	0
Accumulated Depreciation	2
Net Book Value	$ 53
GIla River Unit 3 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	75.00%
Plant in Service	$ 202
Construction Work in Progress	3
Accumulated Depreciation	59
Net Book Value	$ 146
Gila River Common Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	18.80%
Plant in Service	$ 25
Construction Work in Progress	0
Accumulated Depreciation	8
Net Book Value	$ 17
Springerville Coal Handling Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	83.00%
Plant in Service	$ 201
Construction Work in Progress	0
Accumulated Depreciation	80
Net Book Value	121
Transmission Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	383
Construction Work in Progress	3
Accumulated Depreciation	175
Net Book Value	$ 211

UTILITY PLANT AND JOINTLY-OWN53

UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Retirements) (Details) $ in Millions	Dec. 31, 2016USD ($)
Jointly Owned Utility Plant, Net Ownership Amount	$ 885
Sundt [Member]
Coal Handling Facilities Net Book Value Plant Net Ownership Amount	16
San Juan Unit Two [Member]
Jointly Owned Utility Plant, Net Ownership Amount	$ 98

UTILITY PLANT AND JOINTLY-OWN54

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulated Operations [Abstract]
Beginning of Period	$ 32	$ 28
Liabilities Incurred	0	4
Accretion Expense or Regulatory Deferral	2	1
Revisions to the Present Value of Estimated Cash Flows (1)	(1)	(1)
End of Period	$ 33	$ 32

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts (1)	$ (5,000)	$ (27,000)
Accounts Receivable, Net	124,934	136,682
Customer
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	74,000	79,000
Customer | Unbilled
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	34,000	39,000
Customer | Due from Affiliates (Note 5)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	9,000	7,000
Other (1)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	$ 13,000	$ 39,000

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	$ 9,000,000	$ 7,000,000
Payable to Related Parties	2,000,000	6,000,000
Contribution from Parent	0	180,000,000	$ 225,000,000
Dividends Declared to Parent	(50,000,000)	(50,000,000)	(40,000,000)
Dividends Paid to Parent	(50,000,000)	(50,000,000)	(40,000,000)
Transmission Sales To UNS Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Wholesale Sales from Related Parties	7,000,000	6,000,000	1,000,000
Wholesale Sales to UNS Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Wholesale Sales from Related Parties	0	2,000,000	3,000,000
Tucson Electric Power Company To Uns Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Control Area Services, Other Revenues from Transactions with Related Parties	2,000,000	2,000,000	3,000,000
TEP to UNS Energy Affiliates [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Common Costs Charged to Related Parties	14,000,000	12,000,000	13,000,000
Uns Electric To Tucson Electric Power Company [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Wholesale Revenues	1,000,000	1,000,000	4,000,000
Southwest Energy Solutions, Inc. to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Supplemental Workforce	14,000,000	16,000,000	16,000,000
UNS Energy to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services	$ 7,000,000	7,000,000	14,000,000
Intercompany Allocation Parent to Subsidiary	82.00%
Management fee	$ 6,000,000	5,000,000
Contribution from Parent	0	180,000,000	225,000,000
UNS Energy Affiliates to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services	4,000,000	1,000,000	$ 1,000,000
UNS Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	7,000,000	6,000,000
Payable to Related Parties	0	2,000,000
Uns Gas [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	2,000,000	1,000,000
Southwest Energy Solutions, Inc. [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payable to Related Parties	2,000,000	2,000,000
Uns Energy Corporation [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payable to Related Parties	$ 0	$ 2,000,000

DEBT, CREDIT FACILITY, AND CA57

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Long-term Debt) (Detail) - USD ($)	1 Months Ended
	Aug. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Feb. 28, 2015	Jan. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,466,000,000	$ 1,466,000,000
Less Unamortized Discount and Debt Issuance Costs		13,000,000	14,000,000
Long-Term Debt, Net		$ 1,453,072,000	1,451,720,000
Notes 2011 5.15% due 2021 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		5.15%
Long-term Debt, Gross		$ 250,000,000	250,000,000
Notes 2012 3.85% due 2023 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		3.85%
Long-term Debt, Gross		$ 150,000,000	150,000,000
Notes 2014 5.00% due 2044 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		5.00%
Long-term Debt, Gross		$ 150,000,000	150,000,000
Notes 2015 3.05% due 2025 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		3.05%
Long-term Debt, Gross		$ 300,000,000	300,000,000
Debt Instrument, Face Amount				$ 300,000,000
Tax Exempt Local Furnishings Bonds 2010 Pima A due 2040 5.25% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		5.25%
Long-term Debt, Gross		$ 100,000,000	100,000,000
Tax Exempt Local Furnishings Bonds 2012 Pima A due 2030 4.50% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		4.50%
Long-term Debt, Gross		$ 16,000,000	16,000,000
Tax Exempt Local Furnishings Bonds 2013 Pima A due 2029 4.00% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		4.00%
Long-term Debt, Gross		$ 91,000,000	91,000,000
Tax Exempt Local Furnishings Bonds 2013 Apache A due 2032 Variable Rate [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		1.01%
Long-term Debt, Gross		$ 100,000,000	100,000,000
Debt Instrument, Face Amount		$ 100,000,000
Tax Exempt Pollution Control Bonds 2009 Pima A due 2020 4.95% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		4.95%
Long-term Debt, Gross		$ 80,000,000	80,000,000
Tax Exempt Pollution Control Bonds 2009 Coconino A due 2032 5.13% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		5.13%
Long-term Debt, Gross		$ 15,000,000	15,000,000
Tax Exempt Pollution Control Bonds 2010 Coconino A due 2032 Variable Rate [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		1.33%
Long-term Debt, Gross		$ 37,000,000	37,000,000
Debt Instrument, Face Amount		$ 36,700,000
Tax Exempt Pollution Control Bonds 2012 Apache A due 2030 4.50% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)		4.50%
Long-term Debt, Gross		$ 177,000,000	$ 177,000,000
Tax Exempt Local Furnishings Bonds 2008 Pima B 5.75% due 2029 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount					$ 130,000,000
Tax Exempt Variable Rate [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Debt extinguishment	$ 79,000,000

DEBT, CREDIT FACILITY, AND CA58

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Credit Facility) (Details)	1 Months Ended		12 Months Ended
	Oct. 31, 2016	Oct. 31, 2015USD ($)credit_extension	Oct. 31, 2021USD ($)	Dec. 31, 2016USD ($)	Feb. 15, 2017USD ($)	Dec. 31, 2010USD ($)
Line of Credit [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity		$ 250,000,000
Line of Credit Facility, Number of Extensions Allowed | credit_extension		2
Line of Credit Facility, Extension Period		1 year
Line of Credit Facility, Extension Period, October 2021	1 year
Interest rate spread on LIBOR borrowing				1.00%
Interest rate in addition to alternate base rate for alternate base rate loans				0.00%
Line of Credit Facility, Fair Value of Amount Outstanding				$ 0
Line of Credit [Member] | Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Remaining borrowing capacity					$ 250,000,000
Line of Credit [Member] | Revolving Credit Facility [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity			$ 218,000,000
Line of Credit Facility, Extension Period			1 year
Line of Credit [Member] | Revolving Credit Facility Member LOC Sublimit [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity		$ 50,000,000
Line of Credit [Member] | Revolving Credit Facility 2014 and 2010 [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity		270,000,000
Line of Credit [Member] | Term Loan [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity		$ 130,000,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Letter of Credit, Issued in Support of Tax Exempt Bonds						$ 37,000,000
Letter of Credit, Interest Rate at Period End				0.75%

DEBT, CREDIT FACILITY, AND CA59

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Capital Lease) (Details)	1 Months Ended		12 Months Ended			18 Months Ended
	Dec. 31, 2016USD ($)lease	Apr. 30, 2015USD ($)	Dec. 31, 2016USD ($)lease	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Nov. 30, 2016USD ($)	Sep. 16, 2016	Jan. 31, 2016MW	May 31, 2015USD ($)	Jan. 31, 2015USD ($)MW
Debt Instrument [Line Items]
Capital Lease Obligations	$ 91,000,000		$ 91,000,000	$ 69,000,000
Current Obligations Under Capital Leases	51,765,000		51,765,000	14,114,000
Capital Lease Obligations, Noncurrent	39,267,000		39,267,000	55,324,000
Depreciation			146,097,000	138,093,000	$ 126,520,000
Commitment to Purchase Capital Lease Interests			36,000,000	$ 0	$ 109,000,000
Interest Rate Swap [Member]
Debt Instrument [Line Items]
Notional amount	$ 23,000,000		$ 23,000,000
Springerville Common Facilities Lease Debt [Member] | Interest Rate Swap [Member]
Debt Instrument [Line Items]
Fixed rate of interest related to interest rate swap	5.77%		5.77%
Notional amount	$ 23,000,000		$ 23,000,000
Notional amount of debt	$ 9,000,000
Derivative basis spread	1.88%		1.88%	1.88%
Springerville Common Facility Lease Expiring December 2017 [Member]
Debt Instrument [Line Items]
Fixed price to acquire leased interest in facilities			$ 38,000,000
Number of operating lease | lease	1		1
Springerville Common Facility Lease Expiring January 2021[Member]
Debt Instrument [Line Items]
Fixed price to acquire leased interest in facilities			$ 68,000,000
Number of operating lease | lease	2		2
Number of Leases Remaining | lease	2		2
Term of contract, renewal			2 years
Springerville Common Facility Lease Expiring January 2021[Member] | SRP [Member]
Debt Instrument [Line Items]
Lessee Leasing Arrangements,Term of Contract, Renewal Percentage	14.00%		14.00%
Springerville Common Facility Lease Expiring January 2021[Member] | Tri-State [Member]
Debt Instrument [Line Items]
Lessee Leasing Arrangements,Term of Contract, Renewal Percentage	14.00%		14.00%
Springerville Common Facilities [Member]
Debt Instrument [Line Items]
Percentage of interest committed to purchase	17.80%		17.80%
Springerville Common Facilities [Member] | Springerville Common Facility Lease Expiring December 2017 [Member]
Debt Instrument [Line Items]
Commitment to Purchase Capital Lease Interests	$ 38,000,000
Increase in Utility Plant under Capital Lease	36,000,000
Capital Lease Obligations Incurred	$ 36,000,000
Springerville Unit One [Member] | Additional Purchase of Equity Interest
Debt Instrument [Line Items]
Percentage of ownership in generating station										24.80%
Generating capacity purchased, in MWs | MW										96
Springerville Unit One [Member] | Completion of Purchase of Equity Interest [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station								49.50%
Generating capacity purchased, in MWs | MW								192
Percentage Of Ownership In Generating Units							100.00%
Springerville Unit One [Member] | Springerville Unit One Lease [Member] | Additional Purchase of Equity Interest
Debt Instrument [Line Items]
Lease arrangement, fair market value purchase price										$ 46,000,000
Springerville Coal Handling Facilities
Debt Instrument [Line Items]
Percentage of ownership in generating station	83.00%		83.00%
Springerville Coal Handling Facilities | SRP [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station									17.05%
Springerville Coal Handling Facilities | Tri-State [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station									17.05%
Depreciation						$ 1,000,000
Springerville Coal Handling Facilities | Tri-State [Member] | Assets Held under Capital Leases [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station				17.05%
Springerville Coal Handling Facilities | Tri-State [Member] | Electricity Generation Plant, Non-Nuclear [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station	17.05%		17.05%
Springerville Coal Handling Facilities | Additional Purchase of Equity Interest
Debt Instrument [Line Items]
Percentage of ownership in generating station		86.70%
Springerville Coal Handling Facilities | Completion of Purchase of Equity Interest [Member]
Debt Instrument [Line Items]
Percentage Of Ownership In Generating Units		100.00%
Springerville Coal Handling Facilities | Springerville Coal Handling Facilities Lease [Member] | SRP [Member]
Debt Instrument [Line Items]
Sales price of leased interest in facilities									$ 24,000,000
Springerville Coal Handling Facilities | Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member]
Debt Instrument [Line Items]
Sales price of leased interest in facilities									$ 24,000,000
Springerville Coal Handling Facilities | Springerville Coal Handling Facilities Lease [Member] | Additional Purchase of Equity Interest
Debt Instrument [Line Items]
Fixed price to acquire leased interest in facilities		$ 120,000,000

DEBT, CREDIT FACILITY, AND CA60

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Long-Term Debt Maturities
2,017	$ 0
2,018	100
2,019	37
2,020	80
2,021	250
Total 2017 - 2021	467
Thereafter	999
Less: Imputed Interest	0
Total LT Debt	1,466	$ 1,466
Capital Lease Obligations
2,017	52
2,018	11
2,019	11
2,020	18
2,021	0
Total 2017 - 2021	92
Thereafter	0
Less: Imputed Interest	(1)
Capital Lease Obligations	91	$ 69
2,017	52
2,018	111
2,019	48
2,020	98
2,021	250
Total 2017 - 2021	559
Thereafter	999
Less: Imputed Interest	(1)
Total LT Debt and Capital Lease Obligations	$ 1,557

DEBT, CREDIT FACILITY, AND CA61

DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt Footnotes) (Detail)	Dec. 31, 2016USD ($)
Schedule Of Maturities Of Long Term Debt [Line Items]
Unamortized Debt Issuance Expense	$ 10,000,000
Debt discount	3,000,000
Tax Exempt Pollution Control Bonds 2010 Coconino A due 2032 Variable Rate [Member] | Secured Debt [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Debt Instrument, Face Amount	36,700,000
Tax Exempt Local Furnishings Bonds 2013 Apache A due 2032 Variable Rate [Member] | Unsecured Debt [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Debt Instrument, Face Amount	$ 100,000,000

COMMITMENTS AND CONTINGENCIES62

COMMITMENTS AND CONTINGENCIES (COMMITMENTS) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	$ 224
2,018	169
2,019	169
2,020	148
2,021	121
Thereafter	1,147
Unrecorded Unconditional Purchase Obligation	1,978
Operating Leases, Rent Expense	2	$ 3
Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	100
2,018	76
2,019	76
2,020	67
2,021	43
Thereafter	269
Unrecorded Unconditional Purchase Obligation	631
Purchased Power
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	32
2,018	0
2,019	0
2,020	0
2,021	0
Thereafter	0
Unrecorded Unconditional Purchase Obligation	32
Transmission Facilities [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	18
2,018	19
2,019	19
2,020	8
2,021	4
Thereafter	10
Unrecorded Unconditional Purchase Obligation	78
Renewable Energy Power Purchase Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	64
2,018	64
2,019	64
2,020	63
2,021	63
Thereafter	730
Unrecorded Unconditional Purchase Obligation	$ 1,048
Percentage of Purchase Power Obligations	100.00%
RES Performance Based Incentives Minimum Commitment [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	$ 8
2,018	8
2,019	8
2,020	8
2,021	8
Thereafter	59
Unrecorded Unconditional Purchase Obligation	99
Contractual Rights [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	1
2,018	1
2,019	1
2,020	1
2,021	2
Thereafter	75
Unrecorded Unconditional Purchase Obligation	81
Operating Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,017	1
2,018	1
2,019	1
2,020	1
2,021	1
Thereafter	4
Unrecorded Unconditional Purchase Obligation	$ 9

COMMITMENTS AND CONTINGENCIES63

COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Detail) $ in Thousands	1 Months Ended			12 Months Ended
	Jan. 31, 2017USD ($)	Sep. 30, 2016USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2016USD ($)minestate	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments And Contingencies [Line Items]
Payments to Acquire Other Productive Assets				$ 85,000	$ 45,753	$ 19,608
Springerville Unit 1 Third Party Owner Allegation [Member] | Settled Litigation [Member]
Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant Proportionate Ownership Share, Purchased			50.50%
Purchase Obligation			$ 85,000
Litigation Settlement Amount			$ 12,500
Payments to Acquire Other Productive Assets		$ 85,000
Percentage Of Ownership In Generating Units		100.00%
Proceeds from Legal Settlements		$ 12,500
FERC Refund Orders [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual, Provision				22,000
Loss Contingency Accrual, Payments				17,000
FERC Refund Orders [Member] | Wholesale Revenue [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual, Provision				22,000
FERC Refund Orders [Member] | Other Current Liabilities [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual				$ 5,000
FERC Refund Orders [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Litigation Settlement Amount	$ 8,000
San Juan Generating Station and WildEarth Guardians Allegation [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Number of Mines | mine				7
Loss Contingency Number of States | state				4
Navajo [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station				7.50%
Loss Contingency Accrual, Period Increase (Decrease)				$ 5,000
Navajo [Member] | Other Noncurrent Liabilities [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual				3,000
Navajo, San Juan, Four Corners [Member]
Commitments And Contingencies [Line Items]
Share of Reclamation Costs Anticipated				61,000
Navajo, San Juan, Four Corners [Member] | Other Liabilities [Member]
Commitments And Contingencies [Line Items]
Environmental Exit Costs, Costs Accrued to Date				$ 26,000	$ 25,000
Gila [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station				75.00%
Gila [Member] | UNS Electric [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station				25.00%

COMMITMENTS AND CONTINGENCIES C

COMMITMENTS AND CONTINGENCIES COMMITMENTS AND CONTINGENCIES (PERFORMANCE GUARANTEES) (Detail) - Performance Guarantee [Member]	Dec. 31, 2016USD ($)
Guarantor Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	$ 0
Four Corner [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	250,000,000
Navajo, San Juan, Luna [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 0

EMPLOYEE BENEFIT PLANS (Pension

EMPLOYEE BENEFIT PLANS (Pension and Other Postretirement Benefit Amounts included in Consolidated Balance Sheet ) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	$ 281	$ 264
Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	123	115
Accrued Employee Expenses	(1)	(1)
Pension and Other Retiree Benefits	(69)	(57)
Accumulated Other Comprehensive Loss, SERP	6	5
Net Total Amount On Balance Sheet	59	62
Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	5	5
Accrued Employee Expenses	(2)	(2)
Pension and Other Retiree Benefits	(63)	(63)
Accumulated Other Comprehensive Loss, SERP	0	0
Net Total Amount On Balance Sheet	$ (60)	$ (60)

EMPLOYEE BENEFIT PLANS (Change

EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Change in Projected Benefit Obligation
Beginning of Period	$ 394	$ 407
Actuarial (Gain) Loss	20	(22)
Interest Cost	15	17	$ 16
Service Cost	12	12	10
Benefits Paid	(17)	(20)
End of Period	424	394	407
Change in Fair Value of Plan Assets
Beginning of Period	336	335
Actual Return on Plan Assets	27	(3)
Benefits Paid	(17)	(20)
Employer Contributions	8	24
End of Period	354	336	335
Funded Status at End of Period	(70)	(58)
Other Postretirement Benefits [Member]
Change in Projected Benefit Obligation
Beginning of Period	78	81
Actuarial (Gain) Loss	0	(5)
Interest Cost	2	3	3
Service Cost	4	4	4
Benefits Paid	(5)	(5)
End of Period	79	78	81
Change in Fair Value of Plan Assets
Beginning of Period	13	12
Actual Return on Plan Assets	1	0
Benefits Paid	(5)	(5)
Employer Contributions	5	6
End of Period	14	13	$ 12
Funded Status at End of Period	$ (65)	$ (65)

EMPLOYEE BENEFIT PLANS (Expecte

EMPLOYEE BENEFIT PLANS (Expected Pension Contributions For Next Year) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	$ 11

EMPLOYEE BENEFIT PLANS (Compone

EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	$ 128	$ 117
Prior Service Cost (Benefit)	0	3
Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	6	6
Prior Service Cost (Benefit)	$ (1)	$ (1)

EMPLOYEE BENEFIT PLANS (Informa

EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Details) $ in Millions	Dec. 31, 2016USD ($)plans	Dec. 31, 2015USD ($)plans
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]
Number of Defined Benefit Pension Plans with ABO in Excess of Plan Assets | plans	3	2
Pension Plan [Member]
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]
Accumulated Benefit Obligation at End of Year	$ 384	$ 188
Fair Value of Plan Assets at End of Year	$ 354	$ 169

EMPLOYEE BENEFIT PLANS (Compo70

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 12	$ 12	$ 10
Interest Cost	15	17	16
Expected Return on Plan Assets	(23)	(23)	(21)
Amortization of Net Loss	7	7	3
Net Periodic Benefit Cost	11	13	8
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	4	4
Interest Cost	2	3	3
Expected Return on Plan Assets	(1)	(1)	(1)
Amortization of Net Loss	0	0	0
Net Periodic Benefit Cost	$ 5	$ 6	$ 6

EMPLOYEE BENEFIT PLANS (Changes

EMPLOYEE BENEFIT PLANS (Changes in Regulatory Assets and Accumulated Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	$ 15	$ 5	$ 49
Amortization of Net Loss	(7)	(7)	(3)
Total Recognized (Gain) Loss	8	(2)	46
Pension Plan [Member] | Accumulated Other Comprehensive Loss [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	1	0	3
Amortization of Net Loss	0	0	0
Total Recognized (Gain) Loss	1	0	3
Other Postretirement Benefits [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	0	(4)	5
Amortization of Net Loss	0	0	0
Total Recognized (Gain) Loss	$ 0	$ (4)	$ 5

EMPLOYEE BENEFIT PLANS (Future

EMPLOYEE BENEFIT PLANS (Future Amortization) (Details) - Regulatory Asset [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Loss	$ 7
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Loss	$ 0

EMPLOYEE BENEFIT PLANS (Weighte

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Details)	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.20%	4.50%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	2.80%	3.00%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.00%	4.20%

EMPLOYEE BENEFIT PLANS (Weigh74

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate of Compensation Increase	3.00%	3.00%	3.00%
Expected Return on Plan Assets	7.00%	7.00%	7.00%
Pension Plan [Member] | Service cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.80%	4.20%	5.10%
Pension Plan [Member] | Interest Cost Member [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.90%	4.20%	5.10%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Return on Plan Assets	7.00%	7.00%	7.00%
Other Postretirement Benefits [Member] | Service cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.60%	3.90%	4.70%
Other Postretirement Benefits [Member] | Interest Cost Member [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.40%	3.90%	4.70%

EMPLOYEE BENEFIT PLANS(Assumed

EMPLOYEE BENEFIT PLANS(Assumed Health Care Cost Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Health Care Cost Trend Rate Assumed for Next Year	7.60%	7.60%
Ultimate Health Care Cost Trend Rate Assumed	4.50%	4.50%
Year that the Rate Reaches the Ultimate Trend Rate	2,037	2,036

EMPLOYEE BENEFIT PLANS (One-Per

EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Effect of one percentage point increase on service and interest cost components	$ 1
Effect of one percentage point decrease on service and interest cost components	(1)
Effect on Retiree Benefit Obligation, One-Percentage-Point Increase	7
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease	$ (6)

EMPLOYEE BENEFIT PLANS (Percent

EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Details)	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	100.00%	100.00%
Pension Plan [Member] | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	49.00%	49.00%
Pension Plan [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	41.00%	41.00%
Pension Plan [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	8.00%	8.00%
Pension Plan [Member] | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	2.00%	2.00%
Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	100.00%	100.00%
Other Postretirement Benefits [Member] | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	60.00%	60.00%
Other Postretirement Benefits [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	35.00%	35.00%
Other Postretirement Benefits [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	2.00%	2.00%
Other Postretirement Benefits [Member] | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	3.00%	3.00%

EMPLOYEE BENEFIT PLANS (Fair Va

EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Plan Assets By Level) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 26,000,000	$ 25,000,000	$ 23,000,000
Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	19,000,000	18,000,000	16,000,000
Level 3 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7,000,000	7,000,000	7,000,000
Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	354,000,000	336,000,000	335,000,000
Pension Plan [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1,000,000	1,000,000
Pension Plan [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	61,000,000	81,000,000
Pension Plan [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	18,000,000	17,000,000
Pension Plan [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	67,000,000	67,000,000
Pension Plan [Member] | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	28,000,000
Pension Plan [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	144,000,000	137,000,000
Pension Plan [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	28,000,000	26,000,000
Pension Plan [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7,000,000	7,000,000
Pension Plan [Member] | Level 1 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1,000,000	1,000,000
Pension Plan [Member] | Level 1 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1,000,000	1,000,000
Pension Plan [Member] | Level 1 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0
Pension Plan [Member] | Level 1 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 2 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	327,000,000	310,000,000
Pension Plan [Member] | Level 2 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 2 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	61,000,000	81,000,000
Pension Plan [Member] | Level 2 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	18,000,000	17,000,000
Pension Plan [Member] | Level 2 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	67,000,000	67,000,000
Pension Plan [Member] | Level 2 [Member] | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	28,000,000
Pension Plan [Member] | Level 2 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	144,000,000	137,000,000
Pension Plan [Member] | Level 2 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	9,000,000	8,000,000
Pension Plan [Member] | Level 2 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	26,000,000	25,000,000
Pension Plan [Member] | Level 3 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 3 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 3 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 3 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 3 [Member] | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0
Pension Plan [Member] | Level 3 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan [Member] | Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	19,000,000	18,000,000
Pension Plan [Member] | Level 3 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7,000,000	7,000,000
Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	14,000,000	13,000,000	$ 12,000,000
Other Postretirement Benefits [Member] | Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 0	$ 0

EMPLOYEE BENEFIT PLANS (Reconci

EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Details) - Level 3 [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning of Period	$ 25	$ 23
Actual Return on Plan Assets:
Assets Held at Reporting Date	2	3
Purchases, Sales, and Settlements	(1)	(1)
End of Period	26	25
Private Equity
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning of Period	7	7
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	1
Purchases, Sales, and Settlements	(1)	(1)
End of Period	7	7
Real Estate
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning of Period	18	16
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	2
Purchases, Sales, and Settlements	0	0
End of Period	$ 19	$ 18

EMPLOYEE BENEFIT PLANS (Target

EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Details)	12 Months Ended
	Dec. 31, 2016
Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
Cash/Treasury Bills | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
Cash/Treasury Bills | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	2.00%
United States Large Cap | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	17.00%
United States Large Cap | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	39.00%
United States Small Cap | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
United States Small Cap | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
Non-United States Developed | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	15.00%
Non-United States Developed | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	7.00%
Non-United States Emerging | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	4.00%
Non-United States Emerging | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	9.00%
Global Equity | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
Global Equity | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
Global Infrastructure [Member] | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	3.00%
Global Infrastructure [Member] | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
Fixed Income | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	42.00%
Fixed Income | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	38.00%
Real Estate | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	8.00%
Real Estate | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
Private Equity | Pension Plan [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	1.00%
Private Equity | Other Postretirement Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%

EMPLOYEE BENEFIT PLANS (Futur81

EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Details) $ in Millions	Dec. 31, 2016USD ($)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2,017	$ 18
2,018	19
2,019	20
2,020	22
2,021	23
Years 2022-2026	128
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2,017	4
2,018	5
2,019	5
2,020	6
2,021	6
Years 2022-2026	$ 32

EMPLOYEE BENEFIT PLANS (Additio

EMPLOYEE BENEFIT PLANS (Additional Information) (Details)	12 Months Ended
	Dec. 31, 2016USD ($)plans	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Number of defined benefit pension plans | plans	3
number of qualified defined benefit pension plans | plans	2
Approximate percentage of net periodic benefit cost that was capitalized	19.00%	19.00%	19.00%
Investment Return Model Best-Estimate Range	20 years
Matching 401(k) contributions made	$ 5,000,000	$ 5,000,000	$ 5,000,000
Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	26,000,000	25,000,000	23,000,000
Pension Plan [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	384,000,000	355,000,000
Fair value measurements of plan assets	354,000,000	336,000,000	335,000,000
Pension Plan [Member] | Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 26,000,000	25,000,000
Index value percentage of real estate assets	100.00%
Transfers between levels	$ 0	0
Other Postretirement Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employer Contribution to VEBA Trust	2,000,000	4,000,000	3,000,000
Fair value measurements of plan assets	14,000,000	13,000,000	$ 12,000,000
Other Postretirement Benefits [Member] | FairValueInputsLevel1AndLevel2 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	14,000,000	13,000,000
Other Postretirement Benefits [Member] | Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 0	0
Minimum [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used	25.00%
Maximum [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used	75.00%
Fixed Income | Pension Plan [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 144,000,000	137,000,000
Fixed Income | Pension Plan [Member] | Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	0	0
Fixed Income | Other Postretirement Benefits [Member] | FairValueInputsLevel1AndLevel2 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	5,000,000	5,000,000
Equities | Other Postretirement Benefits [Member] | FairValueInputsLevel1AndLevel2 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 9,000,000	$ 8,000,000

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
2011 Stock and Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Comp Accelerated Vesting Expense			$ 2
Deferred Compensation Arrangement with Individual, Compensation Expense			$ 5
2015 Share Unit Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent	$ 4	$ 2
Allocated Share-based Compensation Expense	$ 2	$ 1
Share-based Compensation, Valuation, Share Equivalent, Number	1
2015 Share Unit Plan [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	66,974	47,776
2015 Share Unit Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	33,488	23,888

SUPPLEMENTAL CASH FLOW (Cash Tr

SUPPLEMENTAL CASH FLOW (Cash Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Interest, Net of Amounts Capitalized	$ 61	$ 65	$ 83
Income Taxes	$ 0	$ 0	$ 0

SUPPLEMENTAL CASH FLOW (Non-Cas

SUPPLEMENTAL CASH FLOW (Non-Cash Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Accrued Capital Expenditures	$ 29	$ 28	$ 29
Net Cost of Removal of Interim Retirements (1)	8	1	12
Commitment to Purchase Capital Lease Interests	36	0	109
Capital Lease Obligations (2)	0	0	1
Asset Retirement Obligations (3)	$ (1)	$ 3	$ 4

FAIR VALUE MEASUREMENTS AND D86

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Assets
Cash Equivalents	$ 23	$ 33
Restricted Cash	7	4
Energy Derivative Contract Assets - Regulatory Recovery	3	1
Energy Derivative Contract Assets - No Regulatory Recovery	2	1
Total Assets	35	39
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(3)	(13)
Interest Rate Swap	(2)	(3)
Total Liabilities	(5)	(16)
Net Total Assets (Liabilities)	30	23
Level 1 [Member]
Assets
Cash Equivalents	23	33
Restricted Cash	7	4
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	30	37
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Interest Rate Swap	0	0
Total Liabilities	0	0
Net Total Assets (Liabilities)	30	37
Level 2 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	3	1
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	3	1
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(2)	(10)
Interest Rate Swap	(2)	(3)
Total Liabilities	(4)	(13)
Net Total Assets (Liabilities)	(1)	(12)
Level 3 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	2	1
Total Assets	2	1
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(1)	(3)
Interest Rate Swap	0	0
Total Liabilities	(1)	(3)
Net Total Assets (Liabilities)	$ 1	$ (2)

FAIR VALUE MEASUREMENTS AND D87

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Energy Derivative [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Asset, Gross Amount Recognized in the Balance Sheets	$ 5	$ 2
Derivative Asset, Counterparty Netting	2	1
Collateral Received	0	0
Derivative Asset, Net Amount	3	1
Derivative Liability, Fair Value, Gross Amount Recognized in the Balance Sheets	(3)	(13)
Derivative Liability, Counterparty Netting	(2)	(1)
Collateral Posted	0	0
Derivative Liability, Net Amount	(1)	(12)
Interest Rate Swap [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Liability, Fair Value, Gross Amount Recognized in the Balance Sheets	(2)	(3)
Derivative Liability, Counterparty Netting	0	0
Collateral Posted	0	0
Derivative Liability, Net Amount	$ (2)	$ (3)

FAIR VALUE MEASUREMENTS AND D88

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Derivative [Line Items]
Cash Flow Hedge Loss to be Reclassified to Earnings within the next Twelve Months	$ 1

FAIR VALUE MEASUREMENTS AND D89

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Capital Lease Interest Expense	$ 3,356	$ 3,994	$ 10,249
Long-Term Debt Interest Expense	62,015	61,159	60,577
Purchased Power	85,354	124,764	152,922
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Capital Lease Interest Expense	1,000	2,000	2,000
Long-Term Debt Interest Expense	0	0	1,000
Purchased Power	$ 0	$ 1,000	$ 1,000

FAIR VALUE MEASUREMENTS AND D90

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Percent of gains shared with ratepayers	10.00%
Energy Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$ 12	$ 6	$ (18)

FAIR VALUE MEASUREMENTS AND D91

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) $ in Millions	Dec. 31, 2016USD ($)GWhBTU	Dec. 31, 2015GWhBTU
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Liability, Notional Amount | $	$ 23
Power Contracts (in GWh) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | GWh	2,610	1,752
Gas Contracts (in BBtu) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | BTU	12,355,000,000,000	17,214,000,000,000

FAIR VALUE MEASUREMENTS AND D92

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 [Member] $ in Millions	Dec. 31, 2016USD ($)$ / megawatt_hour	Dec. 31, 2015USD ($)$ / MMBTU$ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$ 2	$ 1
Derivative Liabilities	(1)	(3)
Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	2	1
Derivative Liabilities	$ (1)	(2)
Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets		0
Derivative Liabilities		$ (1)
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / megawatt_hour	20.90	19.20
Minimum [Member] | Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / MMBTU		2.17
Gas Volatility		31.00%
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / megawatt_hour	40	31.35
Maximum [Member] | Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / MMBTU		2.69
Gas Volatility		58.30%

FAIR VALUE MEASUREMENTS AND D93

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning of Period	$ (2,000,000)	$ (9,000,000)
Gains (Losses) Recorded to:
Gains (Losses) Recorded to Net Regulatory Assets or Liabilities - Derivative Instruments	2,000,000	(4,000,000)
Gains/(Losses) Recorded to Electric Wholesale Sales	4,000,000	3,000,000
Settlements	(3,000,000)	8,000,000
End of Period	1,000,000	(2,000,000)
Change in Unrealized Gains (Losses) related to Assets (Liabilities) still held	1,000,000	(1,000,000)
Transfers out of Level 3	$ 0	$ 0

FAIR VALUE MEASUREMENTS AND D94

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Value of derivative instruments in net liability positions with credit risk related features	$ 8,000,000	$ 20,000,000
Additional collateral to post if credit-risk contingent features are triggered	8,000,000
Line of Credit Collateral [Member]
Derivative [Line Items]
Letter of Credit Less Than	0
Outstanding Net Payable Balances for Settled Positions [Member]
Derivative [Line Items]
Additional collateral to post if credit-risk contingent features are triggered	$ 8,000,000

FAIR VALUE MEASUREMENTS AND D95

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Face Value Long-term Debt, including Current Maturities	$ 1,466	$ 1,466
Level 2 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Fair Value, Long-term Debt, including Current Maturities	$ 1,472	$ 1,529

INCOME TAXES (Reconciliation of

INCOME TAXES (Reconciliation of Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Statutory tax rate	35.00%
Federal Income Tax Expense at Statutory Rate	$ 64,000	$ 70,000	$ 56,000
State Income Tax Expense, Net of Federal Deduction	6,000	8,000	7,000
Federal/State Tax Credits	(8,000)	(8,000)	(5,000)
Allowance for Equity Funds Used During Construction	(1,000)	(1,000)	(2,000)
Deferred Tax Asset Valuation Allowance	(2,000)	1,000	0
Other	0	2,000	2,000
Total Federal and State Income Tax Expense	$ 59,376	$ 71,719	$ 57,911

INCOME TAXES (Income Tax Expens

INCOME TAXES (Income Tax Expense Included in Income Statements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Tax Expense (Benefit)
Federal	$ 0	$ 0	$ (1,000)
State	0	0	0
Total Current Tax Expense (Benefit)	0	0	(1,000)
Deferred Tax Expense (Benefit)
Federal	60,000	66,000	54,000
Federal Investment Tax Credits	(6,000)	(6,000)	(4,000)
State	5,000	12,000	9,000
Total Deferred Tax Expense (Benefit)	59,000	72,000	59,000
Total Federal and State Income Tax Expense	$ 59,376	$ 71,719	$ 57,911

INCOME TAXES (The Significant C

INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Gross Deferred Income Tax Assets
Capital Lease Obligations	$ 35,000	$ 27,000
Net Operating Loss Carryforwards	129,000	156,000
Customer Advances and Contributions in Aid of Construction	20,000	20,000
Alternative Minimum Tax Credit	25,000	24,000
Accrued Postretirement Benefits	23,000	23,000
Emission Allowance Inventory	9,000	9,000
Investment Tax Credit Carryforward	32,000	32,000
Other	60,000	53,000
Total Gross Deferred Income Tax Assets	333,000	344,000
Deferred Tax Assets Valuation Allowance	0	(4,000)
Gross Deferred Income Tax Liabilities
Plant, Net	(774,000)	(750,000)
Capital Lease Assets, Net	(24,000)	(12,000)
Pensions	(26,000)	(27,000)
Other	(38,000)	(19,000)
Total Gross Deferred Income Tax Liabilities	(862,000)	(808,000)
Deferred Tax Liabilities, Net, Noncurrent	$ 529,148	$ 468,024

INCOME TAXES (Summary of Tax Ca

INCOME TAXES (Summary of Tax Carryforwards) (Details) $ in Millions	Dec. 31, 2016USD ($)
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	$ 364
Tax Credits	25
Investment Tax Credits	32
State Tax Jurisdiction [Member]
Income Tax Contingency [Line Items]
Tax Credits	$ 10

INCOME TAXES (Loss and Tax Cred

INCOME TAXES (Loss and Tax Credit Carryforwards, Expiration Year) (Details)	12 Months Ended
	Dec. 31, 2016
Minimum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2031
Tax Credit Carryforwards, Expiration Date	Dec. 31, 2032
Alternative Minimum Tax Credit Carryforwards, Expiration Date	None
Minimum [Member] | State Tax Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards, Expiration Date	Dec. 31, 2017
Maximum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2034
Tax Credit Carryforwards, Expiration Date	Dec. 31, 2036
Alternative Minimum Tax Credit Carryforwards, Expiration Date	None
Maximum [Member] | State Tax Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards, Expiration Date	Dec. 31, 2029

INCOME TAXES (Uncertain Tax Pos

INCOME TAXES (Uncertain Tax Positions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Beginning of Period	$ 5	$ 4
Additions Based on Tax Positions Taken in the Current Year	7	1
End of Period	$ 12	$ 5

INCOME TAXES (Additional Inform

INCOME TAXES (Additional Information) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits Reducing Income Tax Expense	$ 1,000,000	$ 1,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Expense	0	0
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	0	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	$ 0	$ 0

QUARTERLY FINANCIAL DATA (UN103

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating Revenue	$ 281,000	$ 394,000	$ 317,000	$ 243,000	$ 284,000	$ 409,000	$ 340,000	$ 273,000	$ 1,234,995	$ 1,306,544	$ 1,269,901
Operating Income	37,000	122,000	72,000	12,000	36,000	120,000	74,000	28,000	243,131	259,303	230,688
Net Income (Loss)	$ 12,000	$ 72,000	$ 41,000	$ (1,000)	$ 12,000	$ 69,000	$ 38,000	$ 9,000	$ 124,438	$ 127,794	$ 102,338