Tucson Electric Power 10-K 18 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 17, 2016	Jun. 30, 2015
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues
Electric Retail Sales	$ 1,021,543	$ 970,145	$ 934,357
Electric Wholesale Sales	167,020	158,323	132,500
Other Revenues	117,981	141,433	129,833
Total Operating Revenues	1,306,544	1,269,901	1,196,690
Operating Expenses
Fuel	305,559	297,537	325,903
Purchased Power	124,764	152,922	112,452
Transmission and Other PPFAC Recoverable Costs	24,798	18,179	12,233
Increase (Decrease) to Reflect PPFAC Recovery Treatment	39,787	(11,194)	(12,458)
Total Fuel and Purchased Power	494,908	457,444	438,130
Operations and Maintenance	345,356	378,877	335,321
Depreciation	138,093	126,520	118,076
Amortization	19,261	28,567	31,294
Taxes Other Than Income Taxes	49,623	47,805	43,498
Total Operating Expenses	1,047,241	1,039,213	966,319
Operating Income	259,303	230,688	230,371
Other Income (Deductions)
Interest Income	93	208	120
Other Income	6,647	8,598	5,770
Other Expense	(2,833)	(12,735)	(10,715)
Appreciation (Depreciation) in Value of Investments	(142)	1,371	2,833
Total Other Income (Deductions)	3,765	(2,558)	(1,992)
Interest Expense
Long-Term Debt	61,159	60,577	56,378
Capital Leases	3,994	10,249	25,140
Other Interest Expense	1,134	810	87
Interest Capitalized	(2,732)	(3,755)	(2,554)
Total Interest Expense	63,555	67,881	79,051
Income Before Income Taxes	199,513	160,249	149,328
Income Tax Expense	71,719	57,911	47,986
Net Income	$ 127,794	$ 102,338	$ 101,342

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net Income	$ 127,794	$ 102,338	$ 101,342
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges:	1,261	1,675	2,738
Supplemental Executive Retirement Plan Adjustments:	101	(1,725)	916
Total Other Comprehensive Income (Loss), Net of Tax	1,362	(50)	3,654
Total Comprehensive Income	$ 129,156	$ 102,288	$ 104,996

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	$ 821	$ 1,140	$ 1,793
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	$ 63	$ (1,068)	$ 572

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Cash Flows [Abstract]
Net Income	$ 127,794	$ 102,338	$ 101,342
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities:
Depreciation Expense	138,093	126,520	118,076
Amortization Expense	19,261	28,567	31,294
Amortization of Debt Issuance Costs	3,043	2,626	2,452
Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue	22,627	0	0
Use of Renewable Energy Credits for Compliance	19,731	17,818	15,990
Deferred Income Taxes	72,026	59,024	58,100
Pension and Retiree Expense	18,588	13,648	19,878
Pension and Retiree Funding	(30,682)	(14,388)	(27,636)
Allowance for Equity Funds Used During Construction	(5,352)	(6,677)	(4,526)
LFCR and DSM Revenues	(14,646)	(12,937)	(2,575)
Increase (Decrease) to Reflect PPFAC Recovery Treatment	39,787	(11,194)	(12,458)
Fortis Acquisition Direct Customer Benefit	0	18,870	0
Change in Current Assets and Current Liabilities:
Accounts Receivable	(25,690)	(14,261)	824
Materials, Supplies, and Fuel Inventory	(8,758)	666	16,145
Accounts Payable	(23,149)	10,712	334
Regulatory Liabilities	(2,977)	8,388	3,331
Other, Net	15,238	(16,057)	25,620
Net Cash Flows—Operating Activities	364,934	313,663	346,191
Cash Flows from Investing Activities
Capital Expenditures	(333,841)	(323,524)	(252,848)
Purchase of Gila River Unit 3	0	(163,938)	0
Purchase of Springerville Coal Handling Facilities Lease Assets	(120,312)	0	0
Purchase of Springerville Unit 1 Lease Assets	(45,753)	(19,608)	0
Proceeds from Sale of Springerville Coal Handling Facilities	23,656	0	0
Purchase of Intangibles - Renewable Energy Credits	(29,184)	(28,334)	(23,280)
Return of Investments in Springerville Lease Debt	0	0	9,104
Contributions in Aid of Construction	4,517	15,903	3,959
Other, Net	(1,974)	1,863	3,403
Net Cash Flows—Investing Activities	(502,891)	(517,638)	(259,662)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	148,000	275,000	78,000
Repayments of Borrowings Under Revolving Credit Facilities	(233,000)	(190,000)	(78,000)
Proceeds from Borrowings Under Term Loan	130,000	0	0
Repayments of Borrowings Under Term Loan	(130,000)	0	0
Proceeds from Issuance of Long-Term Debt	299,019	149,168	0
Repayments of Long-Term Debt	(208,600)	0	0
Dividends Paid to Parent	(50,000)	(40,000)	(40,000)
Payments of Capital Lease Obligations	(13,464)	(165,145)	(99,621)
Payment of Debt Issue/Retirement Costs	(3,942)	(1,856)	(1,865)
Contribution from Parent	180,000	225,000	0
Other, Net	1,458	643	549
Net Cash Flows—Financing Activities	119,471	252,810	(140,937)
Net Increase (Decrease) in Cash and Cash Equivalents	(18,486)	48,835	(54,408)
Cash and Cash Equivalents, Beginning of Period	74,170	25,335	79,743
Cash and Cash Equivalents, End of Period	$ 55,684	$ 74,170	$ 25,335

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Utility Plant
Plant in Service	$ 5,618,435	$ 5,175,148
Utility Plant Under Capital Leases	131,705	667,157
Construction Work in Progress	102,028	109,070
Total Utility Plant	5,852,168	5,951,375
Less Accumulated Depreciation and Amortization	(2,194,301)	(2,052,216)
Less Accumulated Amortization of Capital Lease Assets	(99,638)	(473,969)
Total Utility Plant, Net	3,558,229	3,425,190
Investments and Other Property	39,569	37,599
Current Assets
Cash and Cash Equivalents	55,684	74,170
Accounts Receivable, Net	136,682	131,799
Fuel Inventory	34,600	36,368
Materials and Supplies	94,003	86,750
Regulatory Assets	51,841	69,383
Derivative Instruments	1,808	1,633
Assets Held for Sale, Net	21,550	0
Other	25,904	21,010
Total Current Assets	422,072	421,113
Regulatory and Other Assets
Regulatory Assets	212,312	223,192
Derivative Instruments	430	300
Other	16,866	12,436
Total Regulatory and Other Assets	229,608	235,928
Total Assets	4,249,478	4,119,830
Capitalization
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding at December 31, 2015 and 2014)	1,296,539	1,116,539
Capital Stock Expense	(6,357)	(6,357)
Accumulated Earnings	189,317	111,523
Accumulated Other Comprehensive Loss	(4,564)	(5,926)
Total Common Stock Equity	1,474,935	1,215,779
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding at December 31, 2015 and 2014)	0	0
Capital Lease Obligations	55,324	69,438
Long-Term Debt, Net	1,451,720	1,361,828
Total Capitalization	2,981,979	2,647,045
Current Liabilities
Current Obligations Under Capital Leases	14,114	173,822
Borrowings Under Revolving Credit Facilities	0	85,000
Accounts Payable	86,274	113,413
Accrued Taxes Other than Income Taxes	37,577	36,110
Accrued Employee Expenses	27,718	15,679
Accrued Interest	14,246	21,021
Regulatory Liabilities	53,077	38,847
Customer Deposits	20,349	20,339
Derivative Instruments	12,174	18,874
Other	7,533	9,673
Total Current Liabilities	273,062	532,778
Regulatory and Other Liabilities
Deferred Income Taxes, Net	468,024	389,540
Regulatory Liabilities	307,286	321,186
Pension and Other Postretirement Benefits	120,336	138,319
Derivative Instruments	4,067	6,288
Other	94,724	84,674
Total Regulatory and Other Liabilities	$ 994,437	$ 940,007
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 4,249,478	$ 4,119,830

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common Stock, No Par Value	$ 0	$ 0
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	32,139,434	32,139,434
Preferred Stock, No Par Value	$ 0	$ 0
Preferred Stock, Shares Authorized	1,000,000	1,000,000
Preferred Stock, Shares Outstanding	0	0

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Capital Stock Expense	Accumulated Earnings (Deficit)	Accumulated Other Comprehensive Loss
Balances at December 31 at Dec. 31, 2012	$ 860,927	$ 888,971	$ (6,357)	$ (12,157)	$ (9,530)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	101,342			101,342
Other Comprehensive Loss, net of tax	3,654				3,654
Dividends Declared to Parent	(40,000)			(40,000)
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 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 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)

NATURE OF OPERATIONS AND SUMMAR

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits, and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis). References in these notes to "we" and "our" are to TEP. FORTIS ACQUISITION OF UNS ENERGY UNS Energy, the parent of TEP, was acquired by Fortis for $60.25 per share of UNS Energy common stock in cash, effective August 15, 2014 . The Arizona Corporation Commission's (ACC) approval was subject to certain stipulations, including, but not limited to, the following: • TEP will provide credits on retail customers' bills totaling approximately $19 million over five years: $6 million in year one and $3 million annually in years two through five. The monthly bill credits will be applied each year from October through March effective October 1, 2014 ; • Dividends paid from TEP to UNS Energy cannot exceed 60 percent of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reaches 50 percent of total capital; and • Fortis making an equity investment of at least $220 million to UNS Energy and its regulated subsidiaries, including TEP. Following the UNS Energy acquisition, Fortis exceeded the investment requirement by contributing $287 million to UNS Energy through December 31, 2014. UNS Energy then contributed $225 million to TEP. As a result of the acquisition being completed, TEP recorded approximately $15 million , through August 2014, as its allocated share of acquisition-related expenses, in addition to the customer bill credits discussed above. Acquisition-related expenses, reported in Operations and Maintenance and Other Expense, include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards. See Note 9 for additional information regarding share-based compensation. BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with Generally Accepted Accounting Principles (GAAP) in the United States which includes 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 generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the Consolidated Balance Sheets, and our proportionate share of the operating costs associated with these facilities is included on the consolidated statements of income. See Note 3 for additional information regarding Utility Plant. TEP did not reflect the impacts of acquisition accounting in its financial statements. All adjustments of assets and liabilities to fair value and the resultant goodwill associated with the acquisition were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Most notably, in 2014, TEP elected to change its method of reporting cash flows from the direct to the indirect method to conform to Fortis' presentation election. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS In 2015 , we adopted accounting guidance that: • limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows as we did not have any activities that required application of this accounting guidance. • requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The adoption of this standard resulted in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on the Consolidated Balance Sheets. TEP will continue to account for debt issuance costs related to line-of-credit arrangements as an asset. TEP reclassified $11 million at December 31, 2014 from Other Current Assets and Other Assets to Long-Term Debt to conform to the current year presentation. • simplifies the presentation of deferred taxes by requiring deferred tax assets and liabilities to be classified as noncurrent on the balance sheet. The adoption of this standard resulted in a reclassification of deferred income taxes from Deferred Income Taxes - Current Assets to Deferred Income Taxes - Regulatory and Other Liabilities. TEP reclassified $102 million at December 31, 2014 from Deferred Income Taxes - Current Assets to Deferred Income Taxes - Regulatory and Other Liabilities to conform to the current year presentation. USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect: • assets and liabilities on our balance sheets at the dates of the financial statements; • our disclosures about contingent assets and liabilities at the dates of the financial statements; and • our revenues and expenses in our income statements during the periods presented. Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates. ACCOUNTING FOR REGULATED OPERATIONS We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (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. We evaluate regulatory assets each period and believe 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 We consider 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 $4 million at December 31, 2015 and $2 million at December 31, 2014 . ALLOWANCE FOR DOUBTFUL ACCOUNTS We record 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 in our Consolidated Balance Sheets is summarized as follows: Year Ended December 31, (in millions) 2015 2014 2013 Beginning of Period $ 5 $ 5 $ 5 Increases: Charged to Operating Revenues 23 — — Charged to Operating Expenses 2 2 2 Write-offs (3 ) (2 ) (2 ) End of Period $ 27 $ 5 $ 5 The Allowance for Doubtful Accounts increased in 2015 due to Third-Party Owners' claims at Springerville Unit 1. See Note 7 for additional information regarding the Third-Party Owners' claims. INVENTORY We value materials, supplies, and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials. UTILITY PLANT Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utility plant 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. We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statement as costs are incurred. When a unit of regulated property is retired, we reduce accumulated depreciation 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 in the income statement. The capitalized cost for equity funds is recorded as Other Income in the income statement. The average AFUDC rates on regulated construction expenditures are included in the table below: 2015 2014 2013 Average AFUDC Rates 6.12 % 7.30 % 7.38 % Depreciation We compute depreciation 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 Federal Energy Regulatory Commission (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: 2015 2014 2013 Average Annual Depreciation Rates 2.83 % 2.99 % 3.16 % Utility Plant Under Capital Leases TEP finances the facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities) with capital leases. The capital lease expense incurred consists of Amortization Expense and Interest Expense—Capital Leases. See Note 3 for additional information regarding Utility Plant and Note 6 for additional information related to the lease terms. Computer Software Costs We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense. ASSET RETIREMENT OBLIGATIONS TEP has identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its photovoltaic assets as a result of entering into various ground leases or easement agreements. We record 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, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense and depreciate the capitalized cost over the useful life of the related asset or, when applicable, the terms of the lease subject to ARO requirements. TEP defers costs associated with the majority of its legal AROs as regulatory assets based on the ACC's 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. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities. EVALUATION OF ASSETS FOR IMPAIRMENT We evaluate long-lived assets and investments 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 We defer the costs to issue debt and amortize such costs 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. We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt. OPERATING REVENUES We recognize revenues related to the sale of energy 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 sales contracts that are settled financially, TEP nets the sales contracts with the purchase power contracts and reflects the net amount as Electric Wholesale Sales. TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (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 the 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 Lost Fixed Cost Recovery (LFCR) related to kilowatt-hour (kWh) sales lost due to Energy Efficiency Standards (EE Standards) and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected. PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE We recover actual fuel, purchased power and transmission costs to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); 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 Renewable Energy Standard (RES) requires TEP to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements in 2025 , with distributed generation accounting for 30% of the annual renewable energy requirement. TEP must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out this plan is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates. TEP is required to implement cost-effective Demand Side Management (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 Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through Renewable Energy Credits (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. 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 our balance sheets. 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. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that 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. Prior to 1990, TEP flowed through to ratepayers 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 ratepayers as these tax benefits reverse. See Note 2 for additional information regarding regulatory matters. We account 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 – Noncurrent 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 regulatory assets. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises. Income tax liabilities are allocated to TEP based on its taxable income as reported in the FortisUS Inc. consolidated tax return. TAXES OTHER THAN INCOME TAXES We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies on 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 We use 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 our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the Consolidated Balance Sheets and measure those instruments 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 our derivatives designated as hedging contracts, we formally assess, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, we formally document hedging activity by transaction type and risk management strategy. For our 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 We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees. We recognize the underfunded status of our defined benefit pension plans as a liability on our 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. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees. Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 8 for additional information regarding the employee benefit plans.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS The ACC and the FERC each regulate portions of TEP's utility accounting practices and rates. 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. 2015 RATE CASE In November 2015, TEP filed a general rate case with the ACC based on a test year ended June 30, 2015. The filing requests that new rates be implemented by January 1, 2017 . The key provisions of TEP's general rate case include: • a Base Rate increase of $110 million , or 12% , compared with adjusted test year revenues; • a 7.34% return on original cost rate base of $2.1 billion ; • a request to apply excess depreciation reserves against the unrecovered net book value (NBV) of the San Juan Generating Station (San Juan) Unit 2 and the H. Wilson Sundt Generating Station (Sundt) Coal Handling Facilities due to early retirement; • a request for authority to begin using the Third-Party Owners' portion of Unit 1 of the Springerville Generating Station (Springerville Unit 1) that is available to TEP for dispatch to serve retail customers' needs and to recover the related operating costs through the PPFAC; and • rate design changes that would reduce the reliance on volumetric sales to recover fixed costs and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service. TEP cannot predict the outcome of this proceeding or whether its rate request will be adopted by the ACC in whole or in part. 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 attempts to recover or refund the difference between forecasted fuel costs and those embedded in the current PPFAC and fuel 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 $18 million at December 31, 2015 and under-collected by $19 million at December 31, 2014 . The PPFAC rates during the periods reported were as follows: Period Cents per kWh April 2015 through March 2016 0.68 October 2014 through March 2015 (1) 0.50 May 2014 through September 2014 (1) 0.10 July 2013 through April 2014 (2) (0.14 ) January 2013 through June 2013 0.77 (1) The ACC approved a two-step increase to shift a higher level of recovery into the winter season. (2) The effective date of the 2012 PPFAC rate reduction was deferred to coincide with the effective date of the 2013 Rate Order. San Juan Mine Fire Insurance Proceeds In September 2011, a fire at the underground mine providing coal to San Juan caused interruptions to mining operations and resulted in increased fuel costs. The 2013 Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company (SJCC) and distribution of insurance proceeds to San Juan participants. TEP received insurance proceeds of $1 million in 2015 and $8 million in 2014 . The insurance proceeds offset the deferred fuel costs and are included in the Statements of Cash Flows as an operating activity. The remaining $1 million of unreimbursed fuel costs will be recovered through the PPFAC, in accordance with the 2013 Rate Order. Renewable Energy Standards The ACC’s RES requires TEP and other affected 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. Affected utilities must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge until such costs are reflected in TEP’s Base Rates. The associated lost revenues attributable to meeting distributed generation targets will be partially recovered through the LFCR. In July 2015, TEP submitted its application for the 2016 RES implementation plan that includes a budget of $57 million , which will be partially offset by applying approximately $9 million of previously recovered carryover funds. TEP proposed to recover $48 million through the RES surcharge. The budget will fund the following: (i) the above market cost of renewable energy purchases; (ii) previously awarded performance-based incentives for customer installed distributed generation; (iii) depreciation and a return on TEP's investments in company-owned solar projects; and (iv) various other program costs. TEP expects to receive a decision on the application in the first half of 2016. TEP expects to recognize approximately $9 million of revenue in 2016 as a return on company-owned solar projects. TEP met the overall 2015 RES renewable energy requirement of 5% of retail Kilowatt-hour (kWh) sales and expects to meet the 2016 requirement of 6% of retail kWh sales. 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 REC, which are used to demonstrate compliance with the distributed generation requirement, the company has requested a waiver of the RES distributed generation requirements in its 2016 RES implementation plan. Energy Efficiency Standards In 2010, the ACC approved new EE Standards designed to require 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 . Since the implementation of the EE Standards, TEP’s cumulative annual energy savings are approximately 9.3% of 2015 retail kWh sales. TEP’s compliance with the EE Standards is governed by the ACC’s approval of its annual implementation plan. The EE Standards provide for a DSM surcharge for regulated utilities to recover the costs to implement DSM programs as well as an annual performance incentive. TEP recorded $3 million in 2015 , $2 million in 2014 , and less than $1 million in 2013 related to performance. The performance incentive is recorded in the first quarter of the year and is included in Electric Retail Sales on the Consolidated Statements of Income. In February 2016, the ACC approved TEP’s 2016 energy efficiency implementation plan. Under the 2016 plan, TEP has been approved to recover approximately $14 million from retail customers and will offer customers new and existing DSM programs. Energy savings realized through the programs will count toward Arizona’s EE Standard and the associated lost revenue will be partially recovered through the LFCR. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved energy efficiency programs and 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. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of TEP's total retail revenues. TEP recorded a regulatory asset and recognized LFCR revenues of $12 million in 2015 , $11 million in 2014 , and $2 million in 2013 related to reductions in retail kWh sales for the prior years. LFCR revenues are included in Electric Retail Sales 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 Arizona Court of Appeals considered the question 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. If the Supreme Court upholds the decision without modification, certain TEP rate adjustors may be negatively affected which could have a significant impact on TEP’s ability to recover certain costs between rate cases. TEP filed a brief in support of the ACC’s petition to the Supreme Court for review of the Court of Appeals’ decision, but cannot predict the outcome of this matter. REGULATORY ASSETS AND LIABILITIES Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. With the exception of interest earned on under-recovered PPFAC costs and the ECA, we do not earn a return on regulatory assets. Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers. Regulatory assets and liabilities recorded on the Consolidated Balance Sheets are summarized below: December 31, (in millions) 2015 2014 Regulatory Assets Pension and Other Retiree Benefits (Note 8) $ 120 $ 126 Final Mine Reclamation and Retiree Health Care Costs (1) 28 29 Income Taxes Recoverable through Future Rates (2) 26 31 Property Tax Deferrals (3) 21 21 Springerville Unit 1 Leasehold Improvements - Third Party Owners (4) 21 — LFCR and DSM 16 12 Derivatives (Note 11) 12 18 PPFAC — 19 Springerville Purchase Deferrals (5) — 16 Other Regulatory Assets 20 20 Total Regulatory Assets 264 292 Less Current Portion 52 69 Total Non-Current Regulatory Assets $ 212 $ 223 Regulatory Liabilities Net Cost of Removal for Interim Retirements (6) $ 264 $ 265 Deferred Investment Tax Credits (7) 32 41 RES 25 28 PPFAC 18 — Other Regulatory Liabilities 21 26 Total Regulatory Liabilities 360 360 Less Current Portion 53 39 Total Non-Current Regulatory Liabilities $ 307 $ 321 (1) 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 has the option to recognize its liability associated with final reclamation and retiree health care obligations at present or future value. TEP has elected to recognize these costs at future value and is permitted to fully recover these costs through the PPFAC when paid. TEP expects to make continuous payments through 2037 . (2) 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. (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) Upon expiration of Springerville Unit 1 capital leases in January 2015, TEP recorded a regulatory asset for unamortized leasehold improvement costs that relate to third-party ownership interests. These leasehold improvements, previously recorded in Plant in Service on the Consolidated Balance Sheets, represent investments TEP made through the end of the lease term to ensure that the Springerville Unit 1 facilities continued providing safe, reliable service to TEP's customers. In the 2013 Rate Order, TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10-year amortization period. (5) TEP deferred the increase in lease interest expense relating to the purchase commitments for Springerville Unit 1 and the Springerville Coal Handling Facilities to a regulatory asset because TEP believes the full purchase price is recoverable in rate base. See Note 6 for additional information regarding the Springerville leases. (6) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations 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 Credit (ITC) represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. IMPACTS OF REGULATORY ACCOUNTING If we determine that we no longer meet the criteria for continued application of regulatory accounting, we would be required to write off our regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on our financial statements.

UTILITY PLANT AND JOINTLY-OWNED

UTILITY PLANT AND JOINTLY-OWNED FACILITIES	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
UTILITY PLANT AND JOINTLY-OWNED FACILITES	UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT The following table shows Utility Plant in Service by major class: December 31, (in millions) 2015 2014 Plant in Service Electric Generation Plant $ 2,612 $ 2,388 Electric Transmission Plant 1,008 890 Electric Distribution Plant 1,456 1,398 General Plant 358 338 Intangible Plant - Software Costs (1) (2) 172 149 Intangible Plant - Transmission Rights and Other 7 8 Electric Plant Held for Future Use 5 4 Total Plant in Service $ 5,618 $ 5,175 Utility Plant under Capital Leases (3) $ 132 $ 667 (1) Unamortized computer software costs were $45 million and $31 million as of December 31, 2015 and 2014 , respectively. (2) The amortization of computer software costs was $14 million in 2015 , $17 million in 2014 , and $14 million in 2013 . (3) TEP purchased certain Springerville facilities leased interests in 2015 and 2014. See Note 6 for additional information regarding the Springerville leases. Utility Plant under Capital Leases All utility plant under capital leases is used in generation operations and amortized over the primary lease term. See Note 6 for additional information regarding capital leases. At December 31, 2015 , the utility plant under capital leases represents an undivided one-half interest in certain Springerville Common Facilities. The following table shows the amount of lease expense incurred for generation-related capital leases: Year Ended December 31, (in millions) 2015 2014 2013 Lease Expense Interest Expense – Included in: Capital Leases $ 4 $ 10 $ 25 Operating Expenses – Fuel — 1 2 Amortization of Capital Lease Assets – Included in: Operating Expenses – Fuel 2 6 5 Operating Expenses – Amortization 6 16 15 Total Lease Expense $ 12 $ 33 $ 47 Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available for the major classes of Utility Plant in Service at December 31, 2015 , were as follows: Annual Depreciation Rate (1) Average Remaining Life in Years Electric Generation Plant 3.31% 22 Electric Transmission Plant 1.48% 32 Electric Distribution Plant 2.08% 35 General Plant 5.48% 11 Intangible Plant (2) Various Various (1) The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant. (2) The majority of TEP's investment in intangible plant represents computer software. Computer software is being amortized over its expected useful life of three to five years for smaller application software and average remaining life of three to eight years for large enterprise software. GILA RIVER ACQUISITION In December 2014, TEP and UNS Electric, Inc. (UNS Electric) acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 megawatts (MW) located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 ( 413 MW) for $164 million , and UNS Electric purchased the remaining 25% undivided interest. TEP’s purchase of Gila River Unit 3 was intended to replace the reduction of 195 MW of output from Springerville Unit 1 and the 170 MW of capacity expected to be retired at San Juan in 2017. The transaction was accounted for using the acquisition method of accounting which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date: (in millions) Utility Plant, Net $ 163 Materials and Supplies 2 ARO Obligation Assumed (1) (1 ) Total Purchase Price $ 164 (1) The ARO obligation was recorded at net present value in Regulatory and Other Liabilities - Other on TEP's Consolidated Balance Sheets. JOINTLY-OWNED FACILITIES In addition to Gila River Unit 3, at December 31, 2015 , TEP was a participant in the following jointly-owned generating stations 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% $ 486 $ 12 $ 251 $ 247 Navajo Units 1, 2, and 3 7.5% 148 2 112 38 Four Corners Units 4 and 5 7.0% 102 9 77 34 Luna Energy Facility 33.3% 54 — — 54 Gila River Unit 3 75.0% 198 2 56 144 Gila River Common Facilities 18.8% 25 — 7 18 Springerville Unit 1 (1) 49.5% 319 8 174 153 Springerville Coal Handling Facility (2) 65.9% 164 1 65 100 Transmission Facilities Various 383 1 172 212 Total $ 1,879 $ 35 $ 914 $ 1,000 (1) TEP is obligated to operate the unit for the Third-Party Owners under existing agreements. The Owner Trustees and Co-Trustees are obligated to compensate TEP for their pro rata share of expenses. See Note 6 for additional information regarding the purchase of leased interest. See Note 7 for additional information regarding Springerville Unit 1. (2) TEP owns an additional 17.05% undivided interest in the Springerville Coal Handling Facilities classified as Assets Held for Sale 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, we are responsible for our share of operating and capital costs for the above facilities. We account for our 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 State Implementation Plan (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 San Juan Coal Company’s (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. At December 31, 2015 , the net book value of TEP's share in San Juan Unit 2, including construction work in progress, was $104 million . Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered net book value in its 2015 Rate Case. See Note 2 for additional information regarding the 2015 Rate Case. Sundt In June 2014, the EPA issued a final rule that would require TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues 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. Under the rule, TEP is required to notify the EPA of its decision by March 2017. At December 31, 2015 , the net book value of the Sundt coal handling facilities was $16 million . In August 2015, TEP exhausted its existing coal supply at Sundt and has been operating Sundt with natural gas as a primary fuel source. TEP expects to retire the Sundt coal handling facilities earlier than expected, and has requested to apply excess depreciation reserves against the unrecovered net book value in its 2015 Rate Case. See Note 2 for additional information regarding the 2015 Rate Case. ASSET RETIREMENT OBLIGATIONS The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Regulatory and Other Liabilities on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2015 2014 Beginning of Period $ 28 $ 22 Liabilities Incurred 4 5 Accretion Expense or Regulatory Deferral 1 1 Revisions to the Present Value of Estimated Cash Flows (1) (1 ) — End of Period $ 32 $ 28 (1) Primarily related to changes in expected cost estimates, in conjunction with changes of asset retirement dates of generating facilities.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 Customer $ 79 $ 78 Due from Affiliates (Note 5) 7 5 Unbilled 39 37 Other 39 17 Allowance for Doubtful Accounts (1) (27 ) (5 ) Accounts Receivable, Net $ 137 $ 132 (1) The Allowance for Doubtful Accounts increased in 2015 due to the Third-Party Owners' claims at Springerville Unit 1. See Note 7 for additional information regarding the Third-Party Owners' claims.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
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, Inc. (UNS Gas) and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy affiliates). These transactions include the sale and purchase of power and transmission services, common cost allocations, and the provision of corporate and other labor related services. The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets: December 31, (in millions) 2015 2014 Receivables from Related Parties UNS Electric $ 6 $ 4 UNS Gas 1 1 Total Due from Related Parties $ 7 $ 5 Payables to Related Parties SES $ 2 $ 2 UNS Electric 2 1 UNS Energy 2 — Total Due to Related Parties $ 6 $ 3 The following table presents the components of related party transactions included on the Consolidated Statements of Income: Year Ended December 31, (in millions) 2015 2014 2013 Wholesale Sales - TEP to UNS Electric (1) $ 8 $ 4 $ 1 Wholesale Sales - UNS Electric to TEP (1) 1 4 2 Control Area Services - TEP to UNS Electric (2) 2 3 4 Common Costs - TEP to UNS Energy Affiliates (3) 12 13 12 Supplemental Workforce - SES to TEP (4) 16 16 16 Corporate Services - UNS Energy to TEP (5) 7 14 5 Corporate Services - UNS Energy Affiliates to TEP (6) 1 1 1 (1) TEP and UNS Electric sell power and transmission services to each other at prevailing market prices. (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 include Fortis management fees, legal fees, and audit fees which 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 81% of UNS Energy's allocated costs. In 2015 , these costs included approximately $5 million in Fortis management fees, which began in January 2015 following the August 2014 acquisition. In 2014 , these costs included approximately $12 million in acquisition-related costs (excluding TEP allocated labor related charges). (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 In June 2015, UNS Energy made an equity contribution to TEP of $180 million . TEP used proceeds from the equity contribution to repay the outstanding balances under TEP's revolving credit facilities. The remaining balance of the proceeds was used to redeem bonds in August 2015 and to provide additional liquidity to TEP. See Note 6 for additional information regarding the August 2015 bond redemption. TEP received contributions of $225 million from UNS Energy in 2014 and no contributions in 2013 . DIVIDEND PAID TEP declared and paid $50 million in dividends to UNS Energy in 2015 and $40 million in 2014 and 2013 . The ACC's approval of the acquisition of UNS Energy by Fortis, in August 2014, contained a condition restricting subsidiary dividend payments to UNS Energy by TEP to no more than 60 percent of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reaches 50 percent of total capital as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. As of December 31, 2015 , TEP had not reached the 50 percent of total capital and was therefore still restricted by the condition contained in the ACC's approval order.

DEBT, CREDIT FACILITIES, AND CA

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	EBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS LONG-TERM 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 on the Consolidated Balance Sheets: (dollars in millions) December 31, Debt (1) Interest Rate Maturity Date (3) 2015 2014 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 — Tax Exempt Local Furnishings Bonds 1982 Pima A Irvington Project Reset Weekly (2) 2022 — 39 1982 Pima A TEP Projects Reset Weekly (2) 2022 — 40 2008 Pima B 5.75% 2029 — 130 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 Reset Monthly (2) 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 Reset Weekly (2) 2032 37 37 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt 1,466 1,375 Less Unamortized Discount and Debt Issuance Costs 14 13 Total Long-Term Debt, Net $ 1,452 $ 1,362 (1) As of December 31, 2015 , all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by a LOC. (2) For variable rate debt for which rates are reset weekly, the weighted average rate (including LOC fees and remarketing fees) was 1.24% in 2015 and 1.46% in 2014 . The average weekly interest rate ranged from 0.93% - 1.42% in 2015 and 1.40% - 1.75% during 2014 . For variable rate debt for which rates are reset monthly, the rate is based on a percentage of an index equal to one-month London Interbank Offered Rate (LIBOR) plus a credit spread. The average monthly rate was 0.81% in 2015 and 0.87% in 2014 . The monthly interest rate ranged from 0.79% - 0.87% in 2015 and 0.85% - 0.95% in 2014 . (3) The 2010 Coconino A variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. The 2013 Apache A variable rate bonds are subject to mandatory tender for purchase in 2018. 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. At December 31, 2015, TEP had not remarketed the repurchased bonds and as a result the bonds were not recorded in Long-Term Debt on the Consolidated Balance Sheets. In March 2014, TEP issued and sold $150 million of unsecured notes. TEP may redeem the notes prior to September 2043, with a make-whole premium plus accrued interest. After September 2043, TEP may redeem the notes at par plus accrued interest. 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. In September 2014, TEP's interest rate swap entered into in August 2009 expired. The interest rate swap had the economic effect of converting $50 million of variable rate bonds to a fixed rate of 2.40% from September 2009 to September 2014. CREDIT AGREEMENTS In October 2015, TEP entered into an unsecured credit agreement (2015 Credit Agreement) replacing the 2010 Credit Agreement. The 2015 Credit Agreement provides for a $250 million revolving credit commitment and LOC facility. The LOC sublimit is $50 million . 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. All amounts outstanding under the facility will be due in October 2020, the termination date. The 2015 Credit Agreement allows for two one -year extensions of the facility if certain conditions are satisfied. Interest rates and fees under the 2015 Credit Agreement 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 Alternate Base Rate with no spread for Alternate Base Rate loans. At December 31, 2015 , TEP had no borrowings outstanding included in Current Liabilities on the Consolidated Balance Sheets. As of February 17, 2016 , there was $250 million available under the 2015 Credit Agreement's revolving credit and LOC facilities. In 2015, TEP terminated both the 2010 and 2014 Credit Agreements. The amended 2010 Credit Agreement provided for a $200 million revolving credit commitment and LOCs supporting variable-rate, tax-exempt bonds, with an expiration date of November 2016. The 2014 Credit Agreement, entered into in December 2014, provided for a $130 million term loan commitment and a $70 million revolving credit commitment, with an expiration date of November 2015. At December 31, 2014 , TEP had $85 million in total borrowings outstanding under these agreements which were included in Current Liabilities on the Consolidated Balance Sheets. 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 had an expiration date of December 2014. In February 2014, the LOC was amended to extend the expiration date from 2014 to 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 our 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. At December 31, 2015 , we were in compliance with the terms of our long-term debt, 2015 Credit Agreement, 2013 Covenants Agreement, and 2010 Reimbursement Agreement. CAPITAL LEASE OBLIGATIONS The following table details Capital Lease Obligation on TEP's Consolidated Balance Sheets: December 31, (in millions) 2015 2014 Springerville Unit 1 $ — $ 43 Springerville Coal Handling Facilities — 117 Springerville Common Facilities 69 83 Total Capital Lease Obligations 69 243 Less Current Obligations Under Capital Leases 14 174 Total Capital Lease Obligations, Net $ 55 $ 69 Springerville Unit 1 Capital Lease Purchases In December 2014, TEP purchased a 10.6% leased interest in Springerville Unit 1 representing 41 MW of capacity for the appraised value of $20 million . 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. Upon purchase of the leased interests, TEP reduced Capital Lease Obligations on the Consolidated Balance Sheets for the purchase price. With the completion of the purchases, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. TEP is obligated to operate the unit for the Third-Party Owners under existing agreements. The Owner Trustees and Co-Trustees are obligated to compensate TEP for their pro rata share of expenses. See Note 7 for more information regarding claims relating to Springerville Unit 1. Springerville Coal Handling Facilities Lease Purchase In April 2015, upon expiration of the lease, 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 has until April 2016 to exercise its purchase option. At December 31, 2015 , Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities is classified as Assets Held for Sale on the Consolidated Balance Sheets. Springerville Common Facilities Leases The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. TEP may also exercise a fixed-price purchase provision. The fixed prices for the acquisition of the interests in the common facilities are $38 million in 2017 and $68 million in 2021. 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: • TEP will exercise the purchase options under these contracts; • SRP will be obligated to buy a portion of these facilities; and • Tri-State will be obligated to either: (i) buy a portion of these facilities; or (ii) continue making payments to TEP for the use of these facilities. TEP entered into an interest rate swap 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 at December 31, 2015 consisted of a notional amount of $29 million on which interest was fixed by the swap and a notional amount of $13 million of debt that was not hedged. The applicable margin was 1.88% and 1.75% at December 31, 2015 and 2014 , respectively. TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See 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 Maturities (1) Capital Lease Obligations Total (2) 2016 $ — $ 15 $ 15 2017 — 16 16 2018 100 11 111 2019 37 11 48 2020 80 18 98 Total 2016 - 2020 217 71 288 Thereafter 1,249 — 1,249 Less: Imputed Interest — (2 ) (2 ) Total $ 1,466 $ 69 $ 1,535 (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 is not reduced by $11 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, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS At December 31, 2015 , TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases: (in millions) 2016 2017 2018 2019 2020 Thereafter Total Fuel, Including Transportation $ 78 $ 76 $ 49 $ 49 $ 41 $ 287 $ 580 Purchased Power 28 — — — — — 28 Transmission 6 6 6 4 3 13 38 Renewable Power Purchase Agreements 61 61 61 61 60 750 1,054 RES Performance-Based Incentives 8 8 8 8 8 67 107 Operating Leases: Land Easements and Rights-of-Way 1 1 1 1 1 77 82 Operating Leases Other 1 1 1 1 1 4 9 Total Purchase Commitments $ 183 $ 153 $ 126 $ 124 $ 114 $ 1,198 $ 1,898 Fuel, Including Transportation TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031 . Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more than the minimum purchase obligations to meet its fuel requirements. TEP's fuel costs are recoverable from customers through the PPFAC. Contemporaneously with the sale of SJCC's stock in January 2016, the existing coal sale agreement terminated and a new Coal Supply Agreement (CSA) became effective. The new CSA is between SJCC and PNM and continues through June 30, 2022. TEP is not a party to the new CSA, but has minimum purchase obligations under restructured ownership agreements at San Juan. Estimated future payments, not included in the table above, are $21 million in 2016, $23 million in 2017, $24 million in 2018 and 2019, $23 million in 2020, and $22 million through the end of the contract. TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2016 and 2040 . Purchased Power and Transmission TEP has agreements 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 and expire in 2016 . 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 are based on projected market prices as of December 31, 2015 . TEP has agreements with other utilities to provide transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These contracts expire in various years between 2018 and 2028 . TEP's purchased power and transmission costs are recoverable from customers through the PPFAC mechanism. Renewable Power Purchase Agreements and RES Performance-Based Incentives TEP enters into long-term renewable power purchase agreements 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 these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. These contracts expire in various years between 2030 and 2035 . In February 2016, a facility achieved commercial operation status. The related contract expires in 2036 . Estimated future payments, not included in the table above, are $3 million in each of 2016 through 2020 and $43 million through the end of the contract. TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2 for additional information regarding TEP's RES tariff. Operating Leases Our 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 $3 million in 2015 and 2014 and $2 million in 2013 . CONTINGENCIES Navajo Generating Station Lease Extension Navajo Generating Station (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 . The participants in Navajo, including TEP, have not signed the lease amendment because certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations between the participants are ongoing, and all parties will likely agree to the terms. To become effective, this lease amendment must be signed by all of the participants, approved by the Department of the Interior, and is subject to environmental reviews. Once the lease amendment becomes effective, the participants will be responsible for additional lease costs from the date the Navajo Nation signed the lease amendment. TEP owns 7.5% of Navajo. In 2015 , TEP recorded additional estimated lease expense of approximately $1 million with the expectation that the lease amendment will become effective. TEP's Consolidated Balance Sheets reflect a total liability related to the lease amendment of $3 million and $2 million at December 31, 2015 and 2014 , respectively, recorded in Regulatory and Other Liabilities—Other. Claims Related to Springerville Generating Station Unit 1 In November 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the existing Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning in January 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. In February 2015, the FERC issued an order denying the Third-Party Owners complaint. In March 2015, the Third-Party Owners filed a request for rehearing in the FERC Action, which the FERC denied in October 2015. In December 2015, the Third-Party Owners appealed the FERC’s order denying the Third-Party Owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015, TEP filed an unopposed motion to intervene in the Ninth Circuit appeal. On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action). In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged, and the court’s subsequent ruling on the motions, the Third-Party Owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain, and make capital investments in Springerville Unit 1 during the term of the leases and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. The third amended complaint seeks $71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The Third-Party Owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015, the Third-Party Owners filed a motion for summary judgment on their claim that TEP has failed to pay certain of the Third-Party Owners’ claimed expenses. In December 2014 and January 2015, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent notices to TEP that alleged that TEP had defaulted under the Third-Party Owners’ leases. The notices demanded that TEP pay liquidated damages totaling approximately $71 million . In letters to the Owner Trustees, TEP denied the allegations in the notices. In April 2015, TEP filed a demand for arbitration with the American Arbitration Association (AAA) seeking an award of the Owner Trustees and Co-Trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015, the Third-Party Owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The Third-Party Owners’ arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the Third-Party Owners’ fees and expenses. TEP and the Third-Party Owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015, the Third-Party Owners filed an amended arbitration demand adding claims that TEP has converted the Third-Party Owners’ water rights and certain emission reduction payments and that TEP is improperly dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. In October 2015, the arbitration panel granted TEP’s motion for interim relief, ordering the Owner Trustees and Co-Trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the Third-Party Owners’ motion for interim relief which had requested that TEP be enjoined from dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling, when economical, the Third-Party Owners’ entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 14, 2015. The arbitration hearing is scheduled for July 2016. In November 2015, TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming the Owner Trustee and Co-Trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015, the Owner Trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order. As of December 31, 2015 , TEP has billed the Third-Party Owners approximately $23 million for their pro-rata share of Springerville Unit 1 expenses and $4 million for their pro-rata share of capital expenditures, none of which had been paid as of February 17, 2016 . TEP cannot predict the outcome of the claims relating to Springerville Unit 1, and, due to the general and non-specific scope and nature of the claims, TEP cannot determine estimates of the range of loss, if any, at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners and to vigorously pursue the claims it has asserted against the Third-Party Owners. TEP and the Third-Party Owners have agreed to stay these litigation matters relating to Springerville Unit 1 in furtherance of settlement negotiations. However, there is no assurance that a settlement will be reached or that the litigation will not continue. Claims Related to San Juan Generating Station In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million . TEP owns 50% of Units 1 and 2 at San Juan, which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot predict the final outcome of the BLM’s proposed regulations. In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court 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 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 OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against OSM, including, but not limited to, 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 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 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. The parties have requested the court to stay this matter until April 2016, in furtherance of settlement negotiations. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and San Juan. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Claims Related to Four Corners Generating Station In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the U.S. District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs sought to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. In June 2015, APS, the operator of Four Corners, announced a settlement with the Environmental Protection Agency (EPA) for outstanding environmental issues related to New Source Review provisions under the Clean Air Act. The settlement calls for environmental upgrades including Selective Catalytic Reduction (SCR) upgrades already planned for under the Regional Haze regulation, environmental mitigation projects, and civil penalties. A consent decree reflecting terms of the settlement was entered by the court in August 2015 , effectively closing the case. TEP's share of the additional capital, excluding the SCR upgrades, is approximately $2 million over the three year period it will take to construct the upgrades. TEP’s share of the annual O&M expenses is approximately $1 million . In addition, TEP recorded less than $1 million for its share of the one-time charges for environmental mitigation projects and civil penalties. In May 2013, the New Mexico Taxation and Revenue Department (NMTRD) issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. TEP's share of the assessment is $1 million based on our ownership percentage. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. In June 2015, the U.S. District Court ruled in favor of the Four Corners' participants. NMTRD filed an appeal of the decision in August 2015. TEP cannot predict the final outcome or timing of resolution of these claims. Mine Closure Reclamation at Generating Stations Not Operated by TEP TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final 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 $43 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The reclamation liability recorded was $25 million and $22 million at December 31, 2015 and 2014 , respectively. Amounts recorded for final 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 reclamation costs, as a component of fuel cost, 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. Discontinued Transmission Project TEP and UNS Electric had initiated a project to jointly construct a 60 -mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345 -kilo-volt (kV) line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case. Performance Guarantees TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and the Luna Energy Facility (Luna). The participants in each of the generating stations, 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 generating capacity of the defaulting participant. As of December 31, 2015 , 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, 2015
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 are for substantially all employees. We fund those plans by contributing at least the minimum amount required under the Internal Revenue Service (IRS) regulations. We also maintain a Supplemental Executive Retirement Plan (SERP) for executive management. OTHER RETIREE BENEFIT PLANS 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 retiree benefits for classified employees through a Voluntary Employee Beneficiary Association (VEBA). TEP contributed $4 million in 2015 and $3 million in 2014 and 2013 to the VEBA. Other retiree benefits for unclassified employees are self-funded. REGULATORY RECOVERY We record changes in our non-SERP pension plans and other retiree 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 since SERP expense is not currently recoverable in rates. The following table summarizes pension and other retiree benefit related amounts (excluding tax balances) included on the Consolidated Balance Sheets: Pension Benefits Other Retiree Benefits December 31, (in millions) 2015 2014 2015 2014 Regulatory Pension Asset Included in Regulatory Assets $ 115 $ 117 $ 5 $ 9 Accrued Benefit Liability Included in Accrued Employee Expenses (1 ) (1 ) (2 ) (2 ) Accrued Benefit Liability Included in Pension and Other Retiree Benefits (57 ) (71 ) (63 ) (67 ) Accumulated Other Comprehensive Loss (related to SERP) 5 5 — — Net Amount Recognized $ 62 $ 50 $ (60 ) $ (60 ) OBLIGATIONS AND FUNDED STATUS We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2015 and 2014 . The table below includes all of TEP’s plans. All plans have projected benefit obligations in excess of the fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below: Pension Benefits Other Retiree Benefits Year Ended December 31, (in millions) 2015 2014 2015 2014 Change in Projected Benefit Obligation Benefit Obligation at Beginning of Year $ 407 $ 330 $ 81 $ 74 Actuarial (Gain) Loss (22 ) 67 (5 ) 5 Interest Cost 17 16 3 3 Service Cost 12 10 4 4 Benefits Paid (20 ) (16 ) (5 ) (5 ) Projected Benefit Obligation at End of Year 394 407 78 81 Change in Plan Assets Fair Value of Plan Assets at Beginning of Year 335 307 12 10 Actual Return on Plan Assets (3 ) 35 — 1 Benefits Paid (20 ) (16 ) (5 ) (5 ) Employer Contributions (1) 24 9 6 6 Fair Value of Plan Assets at End of Year 336 335 13 12 Funded Status at End of Year $ (58 ) $ (72 ) $ (65 ) $ (69 ) (1) In 2016 , TEP expects to contribute $10 million to the pension plans. 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 Retiree Benefits Year Ended December 31, (in millions) 2015 2014 2015 2014 Net Loss $ 117 $ 118 $ 6 $ 11 Prior Service Cost (Benefit) 3 4 (1 ) (2 ) The accumulated benefit obligation aggregated for all pension plans is $355 million and $365 million at December 31, 2015 and 2014 , respectively. All three of our pension plans had accumulated benefit obligations in excess of plan assets at December 31, 2014 . As a result of increases in discount rates and employer contributions, two of our plans had accumulated benefit obligations in excess of plan assets at 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) 2015 2014 Accumulated Benefit Obligation $ 188 $ 365 Fair Value of Plan Assets 169 335 Net periodic benefit plan cost includes the following components: Pension Benefits Other Retiree Benefits Year Ended December 31, (in millions) 2015 2014 2013 2015 2014 2013 Service Cost $ 12 $ 10 $ 11 $ 4 $ 4 $ 3 Interest Cost 17 16 14 3 3 3 Expected Return on Plan Assets (23 ) (21 ) (19 ) (1 ) (1 ) (1 ) Actuarial Loss Amortization 7 3 8 — — — Net Periodic Benefit Cost $ 13 $ 8 $ 14 $ 6 $ 6 $ 5 Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income. We 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. At the end of 2015, we changed our approach to determine the service and interest cost components of pension and other postretirement benefit expense. We elected to measure service and interest costs by applying the specific spot rates along that yield curve to the plans' liability cash flows beginning in 2016. 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 our plan obligations nor the funded status. We accounted for this change as a change in accounting estimate, and accordingly, have 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 Regulatory Asset AOCI (in millions) 2015 2014 2013 2015 2014 2013 Current Year Actuarial (Gain) Loss $ 5 $ 49 $ (42 ) $ — $ 3 $ (1 ) Amortization of Actuarial Gain (Loss) (7 ) (3 ) (8 ) — — — Total Recognized (Gain) Loss $ (2 ) $ 46 $ (50 ) $ — $ 3 $ (1 ) Other Retiree Benefits Regulatory Asset (in millions) 2015 2014 2013 Current Year Actuarial (Gain) Loss $ (4 ) $ 5 $ (6 ) For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We expect to amortize an estimated $7 million net loss from pension regulatory assets and an estimated $1 million in prior service credit from other retiree benefit plan regulatory assets into net periodic benefit cost in 2016 . The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Retiree Benefits 2015 2014 2015 2014 Discount Rate 4.5-4.6% 4.1-4.2% 4.2% 3.9% Rate of Compensation Increase 3.0% 3.0% N/A N/A The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Retiree Benefits 2015 2014 2013 2015 2014 2013 Discount Rate 4.1%-4.2% 5.0%-5.1% 4.1%-4.1% 3.9% 4.7% 3.8% 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% 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. We use 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. 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. The following table includes the assumed health care cost trend rates: December 31, 2015 2014 Next Year 7.6% 6.7% Ultimate Rate Assumed 4.5% 4.5% Year Ultimate Rate is Reached 2036 2027 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 December 31, 2015 amounts: (in millions) One-Percentage- Point Increase One-Percentage- Point Decrease Effect on Total Service and Interest Cost Components $ 1 $ 1 Effect on Retiree Benefit Obligation 6 5 PENSION PLAN AND OTHER RETIREE BENEFIT ASSETS Pension Assets We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows: 2015 2014 Asset Category Equity Securities 49 % 48 % Fixed Income Securities 41 % 43 % Real Estate 8 % 7 % Other 2 % 2 % Total 100 % 100 % The following table sets forth the fair value measurements of pension plan assets by level within the fair value hierarchy: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (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 (in millions) December 31, 2014 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 82 — 82 United States Small Cap — 17 — 17 Non-United States — 61 — 61 Fixed Income — 143 — 143 Real Estate — 8 16 24 Private Equity — — 7 7 Total $ 1 $ 311 $ 23 $ 335 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 Beginning Balance at January 1, 2014 $ 7 $ 14 $ 21 Actual Return on Plan Assets: Assets Held at Reporting Date 1 2 3 Purchases, Sales, and Settlements (1 ) — (1 ) Ending Balance at 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 ) Ending Balance at December 31, 2015 $ 7 $ 18 $ 25 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. We consider 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. We expect 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 We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize 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. We have 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 as of December 31, 2015 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced. TEP Plans VEBA Trust Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 24% 39% United States Small Cap 5% 5% Non-United States Developed 15% 7% Non-United States Emerging 5% 9% 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, our 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, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds. Other Retiree Benefit Assets 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. As of December 31, 2014 , the fair value of VEBA trust assets was $12 million , of which $4 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. ESTIMATED FUTURE BENEFIT PAYMENTS TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate. (in millions) 2016 2017 2018 2019 2020 2021-2025 Pension Benefits $ 17 $ 18 $ 19 $ 21 $ 22 $ 125 Other Retiree Benefits 5 5 5 6 6 33 DEFINED CONTRIBUTION PLAN We offer 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. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in 2015 , 2014 , and 2013 .

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
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 and $3 million for the year ended December 31, 2013. 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 converted to U.S. dollars. Fortis common stock is traded on the Toronto Stock Exchange. TEP’s share of the obligation and expense as a subsidiary of UNS Energy is allocated based on the Massachusetts Formula. UNS Energy awarded 47,776 PSUs and 23,888 RSUs in 2015 that are payable on the third anniversary of the grant date. 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. At December 31, 2015 , TEP's allocated share of probable payout is $2 million . TEP's allocated portion of the compensation expense is recognized in Operations and Maintenance 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 $1 million for the year ended December 31, 2015 based on its share of UNS Energy's compensation expense.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Year Ended December 31, (in millions) 2015 2014 2013 Interest, Net of Amounts Capitalized $ 65 $ 83 $ 53 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: Year Ended December 31, (in millions) 2015 2014 2013 Accrued Capital Expenditures $ 28 $ 29 $ 24 Net Cost of Removal of Interim Retirements (1) 1 12 25 Commitment to Purchase Capital Lease Interests — 109 55 Capital Lease Obligations (2) — 1 9 Proceeds from Issuance of Long-Term Debt Deposited in Trust — — 191 Asset Retirement Obligations (3) 3 4 8 (1) The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations 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 asset retirement obligations and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future asset retirement obligations.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
Disclosure Text Block [Abstract]
FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS We categorize our 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, 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 (in millions) December 31, 2014 Assets Cash Equivalents (1) $ 15 $ — $ — $ 15 Restricted Cash (1) 2 — — 2 Energy Derivative Contracts - Regulatory Recovery (2) — — 2 2 Total Assets 17 — 2 19 Liabilities Energy Derivative Contracts - Regulatory Recovery (2) — (9 ) (9 ) (18 ) Energy Derivative Contracts - No Regulatory Recovery (2) — — (1 ) (1 ) Energy Derivative Contracts - Cash Flow Hedge (2) — — (1 ) (1 ) Interest Rate Swap (3) — (5 ) — (5 ) Total Liabilities — (14 ) (11 ) (25 ) Net Total Assets (Liabilities) $ 17 $ (14 ) $ (9 ) $ (6 ) (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), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014 a power sale option (Level 3). 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. We present derivatives on a gross basis on the balance sheet. The tables below presents the potential offset of counterparty netting and cash collateral. Gross Amount Recognized on the Balance Sheets Gross Amount Not Offset on the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (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 ) (in millions) December 31, 2014 Derivative Assets Energy Derivative Contracts $ 2 $ 2 $ — $ — Derivative Liabilities Energy Derivative Contracts (20 ) (2 ) — (18 ) Interest Rate Swap (5 ) — — (5 ) DERIVATIVE INSTRUMENTS We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC. We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers. For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe 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, we apply adjustments based on historical price curve relationships, transmission, and line losses. We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. The December 31, 2014 valuation of our power sale option was a function of observable market variables, regional power and gas prices, as well as the ratio between the two, which represents the prevailing market heat rate. We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data. The inputs and our 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. We review the assumptions underlying our price curves monthly. Cash Flow Hedges We can enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. We have an interest rate swap agreement that expires January 2020 . We also had a power purchase 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 . The realized losses from our cash flow hedges are shown in the following table: Year Ended December 31, (in millions) 2015 2014 2013 Capital Lease Interest Expense $ 2 $ 2 $ 2 Long-Term Debt Interest Expense — 1 1 Purchased Power 1 1 1 As of December 31, 2015 , the total notional amount of our interest rate swap was $29 million . Energy Derivative Contracts - Regulatory Recovery We record 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: Year Ended December 31, (in millions) 2015 2014 2013 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ 6 $ (18 ) $ — Energy Derivative Contracts - No Regulatory Recovery Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For these contracts that qualify as derivatives, we record unrealized gains and losses in the income statement, unless and until a normal purchase or normal sale election is made. In February 2015, TEP made a normal sale election for a three -year sales option contract entered into in December 2014. In June 2015, TEP entered into long-term power trading contracts that qualify as derivatives but do not qualify for regulatory recovery. The unrealized gains and losses on the 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 At December 31, 2015 , we have energy contracts that will settle through the fourth quarter of 2018 . The volumes associated with our energy contracts were as follows: December 31, 2015 2014 Power Contracts GWh 1,752 2,604 Gas Contracts GBtu 17,214 19,932 Level 3 Fair Value Measurements The following table provides 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, 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 ) (in millions) December 31, 2014 Forward Power Contracts Market approach $ 1 $ (6 ) Market price per MWh $ 22.35 $ 39.05 Power Sale Option Market approach 1 (1 ) Market price per MWh $ 27.75 $ 44.94 Market price per MMbtu $ 2.88 $ 4.02 Gas Option Contracts Option model — (4 ) Market price per MMbtu $ 2.72 $ 3.26 Gas volatility 30.8 % 53.3 % Level 3 Energy Contracts $ 2 $ (11 ) 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 on the balance sheet 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: Year Ended December 31, (in millions) 2015 2014 Beginning of Period $ (9 ) $ (2 ) Gains (Losses) Recorded to: (1) Net Regulatory Assets/Liabilities – Derivative Instruments (4 ) (8 ) Electric Wholesale Sales 3 — Settlements 8 1 End of Period $ (2 ) $ (9 ) (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 $(8) million for the years ended December 31, 2015, and 2014 , 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. We enter 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. We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties. We consider 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 allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. Material adverse changes could trigger credit risk-related contingent features. At December 31, 2015 , 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 $20 million , compared with $27 million at December 31, 2014 . At December 31, 2015 , TEP had less than $1 million of LOCs as credit enhancements with its counterparties. If the credit risk-related contingent features were triggered on December 31, 2015 , TEP would have been required to post an additional $20 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. We use the following methods and assumptions for estimating the fair value of our financial instruments: • Borrowings under revolving credit facilities approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below. • For long-term debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our 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 our long-term debt: Fair Value Hierarchy Face Value Fair Value December 31, (in millions) 2015 2014 2015 2014 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,375 $ 1,529 $ 1,457

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
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: Year Ended December 31, (in millions) 2015 2014 2013 Federal Income Tax Expense at Statutory Rate $ 70 $ 56 $ 52 State Income Tax Expense, Net of Federal Deduction 8 7 7 Federal/State Tax Credits (8 ) (5 ) (2 ) Allowance for Equity Funds Used During Construction (1 ) (2 ) (1 ) Deferred Tax Asset Valuation Allowance 1 — 2 Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset — — (11 ) Other 2 2 1 Total Federal and State Income Tax Expense $ 72 $ 58 $ 48 Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the assets and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated. Income tax expense included in the income statements consists of the following: Year Ended December 31, (in millions) 2015 2014 2013 Current Tax Expense (Benefit) Federal $ — $ (1 ) $ (8 ) State — — (2 ) Total Current Tax Expense (Benefit) — (1 ) (10 ) Deferred Tax Expense (Benefit) Federal 66 54 47 Federal Investment Tax Credits (6 ) (4 ) (1 ) State 12 9 12 Total Deferred Tax Expense (Benefit) 72 59 58 Total Federal and State Income Tax Expense $ 72 $ 58 $ 48 The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2015 2014 Gross Deferred Income Tax Assets Capital Lease Obligations $ 27 $ 96 Net Operating Loss Carryforwards 156 187 Customer Advances and Contributions in Aid of Construction 20 19 Alternative Minimum Tax Credit 24 24 Accrued Postretirement Benefits 23 23 Emission Allowance Inventory 9 10 Investment Tax Credit Carryforward 32 31 Other 53 54 Total Gross Deferred Income Tax Assets 344 444 Deferred Tax Assets Valuation Allowance (4 ) (2 ) Gross Deferred Income Tax Liabilities Plant, Net (750 ) (699 ) Capital Lease Assets, Net (12 ) (74 ) Pensions (27 ) (27 ) PPFAC — (8 ) Other (19 ) (24 ) Total Gross Deferred Income Tax Liabilities (808 ) (832 ) Net Deferred Income Tax Liabilities $ (468 ) $ (390 ) TEP has recorded a $4 million valuation allowance against credit and loss carryforward deferred tax assets at December 31, 2015 and a $2 million valuation allowance against credit carryforward deferred tax assets at December 31, 2014 . Management believes TEP will not produce sufficient taxable income to use all credit and loss carryforwards before they expire. As of December 31, 2015 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 430 2031-34 State Net Operating Loss 114 2016-34 State Credits 10 2016-30 Alternative Minimum Tax Credit 24 None Investment Tax Credits 32 2032-35 Uncertain Tax Positions A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2015 2014 Beginning of Period $ 4 $ 2 Additions Based on Tax Positions Taken in the Current Year 1 2 End of Period $ 5 $ 4 Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million at December 31, 2015 and would not reduce income tax expense at December 31, 2014 . TEP recorded no interest expense during 2015 and 2014 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued at December 31, 2015 and 2014 . 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 we are unable to determine the amount of change.

RECENTLY ISSUED ACCOUNTING PRON

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	12 Months Ended
	Dec. 31, 2015
Disclosure Text Block [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS We consider the applicability and impact of all Accounting Standards Updates. Updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position, results of operations, or disclosures. Revenue from Contracts with Customers In May 2014, the FASB issued an accounting standards update that will eliminate the transaction and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. The revenue standard requires entities to apply the guidance retrospectively or recognize the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. In July 2015, the FASB voted to defer the effective date of the revenue recognition standard by one year. We are required to adopt the new guidance for annual and interim periods beginning January 1, 2018. Retail sales of electricity based on regulator-approved tariff rates represent TEP's primary source of revenue. While it is expected that tariff-based sales to regulated customers are within the scope of the new standard, this question is being reviewed by the AICPA Financial Reporting Executive Committee. TEP is in the process of assessing its performance obligations in its wholesale contracts and identifying other contracts with customers. Classification and Measurement of Financial Instruments In January 2016, the FASB amended the guidance on the classification and measurement of financial instruments. Most notably, the new accounting standard update requires the following: • all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and • financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2018. TEP is evaluating the impact to our financial statements and disclosures.

QUARTERLY FINANCIAL DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA	QUARTERLY FINANCIAL DATA (UNAUDITED) Our quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our 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) 2015 Operating Revenue $ 273 $ 340 $ 409 $ 284 Operating Income 28 74 120 36 Net Income 9 38 69 12 (in millions) 2014 Operating Revenue $ 256 $ 322 $ 387 $ 305 Operating Income 32 80 85 34 Net Income 9 39 40 15

NATURE OF OPERATIONS AND SUMM23

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Financial Statement Presentation	Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits, and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis).
Basis Of Presentation	BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with Generally Accepted Accounting Principles (GAAP) in the United States which includes 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 generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the Consolidated Balance Sheets, and our proportionate share of the operating costs associated with these facilities is included on the consolidated statements of income. See Note 3 for additional information regarding Utility Plant. TEP did not reflect the impacts of acquisition accounting in its financial statements. All adjustments of assets and liabilities to fair value and the resultant goodwill associated with the acquisition were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Most notably, in 2014, TEP elected to change its method of reporting cash flows from the direct to the indirect method to conform to Fortis' presentation election.
Recently Adopted Accounting Pronouncements	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS In 2015 , we adopted accounting guidance that: • limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows as we did not have any activities that required application of this accounting guidance. • requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The adoption of this standard resulted in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on the Consolidated Balance Sheets. TEP will continue to account for debt issuance costs related to line-of-credit arrangements as an asset. TEP reclassified $11 million at December 31, 2014 from Other Current Assets and Other Assets to Long-Term Debt to conform to the current year presentation. • simplifies the presentation of deferred taxes by requiring deferred tax assets and liabilities to be classified as noncurrent on the balance sheet. The adoption of this standard resulted in a reclassification of deferred income taxes from Deferred Income Taxes - Current Assets to Deferred Income Taxes - Regulatory and Other Liabilities. TEP reclassified $102 million at December 31, 2014 from Deferred Income Taxes - Current Assets to Deferred Income Taxes - Regulatory and Other Liabilities to conform to the current year presentation.
Use of Accounting Estimates	USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect: • assets and liabilities on our balance sheets at the dates of the financial statements; • our disclosures about contingent assets and liabilities at the dates of the financial statements; and • our revenues and expenses in our income statements during the periods presented. Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.
Accounting for Regulated Operations	ACCOUNTING FOR REGULATED OPERATIONS We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (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. We evaluate regulatory assets each period and believe 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 We consider 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 $4 million at December 31, 2015 and $2 million at December 31, 2014 .
Allowance for Doubtful Accounts	ALLOWANCE FOR DOUBTFUL ACCOUNTS We record 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 in our Consolidated Balance Sheets is summarized as follows: Year Ended December 31, (in millions) 2015 2014 2013 Beginning of Period $ 5 $ 5 $ 5 Increases: Charged to Operating Revenues 23 — — Charged to Operating Expenses 2 2 2 Write-offs (3 ) (2 ) (2 ) End of Period $ 27 $ 5 $ 5 The Allowance for Doubtful Accounts increased in 2015 due to Third-Party Owners' claims at Springerville Unit 1. See Note 7 for additional information regarding the Third-Party Owners' claims.
Inventory	INVENTORY We value materials, supplies, and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.
Utility Plant	UTILITY PLANT Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utility plant 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. We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statement as costs are incurred. When a unit of regulated property is retired, we reduce accumulated depreciation 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 in the income statement. The capitalized cost for equity funds is recorded as Other Income in the income statement. The average AFUDC rates on regulated construction expenditures are included in the table below: 2015 2014 2013 Average AFUDC Rates 6.12 % 7.30 % 7.38 %
Depreciation	Depreciation We compute depreciation 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 Federal Energy Regulatory Commission (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: 2015 2014 2013 Average Annual Depreciation Rates 2.83 % 2.99 % 3.16 %
Utility Plant Under Capital Leases	Utility Plant Under Capital Leases TEP finances the facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities) with capital leases. The capital lease expense incurred consists of Amortization Expense and Interest Expense—Capital Leases. 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 We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS TEP has identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its photovoltaic assets as a result of entering into various ground leases or easement agreements. We record 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, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense and depreciate the capitalized cost over the useful life of the related asset or, when applicable, the terms of the lease subject to ARO requirements. TEP defers costs associated with the majority of its legal AROs as regulatory assets based on the ACC's 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. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.
Evaluation of Assets for Impairment	EVALUATION OF ASSETS FOR IMPAIRMENT We evaluate long-lived assets and investments 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 We defer the costs to issue debt and amortize such costs 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. We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.
Operating Revenues	OPERATING REVENUES We recognize revenues related to the sale of energy 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 sales contracts that are settled financially, TEP nets the sales contracts with the purchase power contracts and reflects the net amount as Electric Wholesale Sales. TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (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 the 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 Lost Fixed Cost Recovery (LFCR) related to kilowatt-hour (kWh) sales lost due to Energy Efficiency Standards (EE Standards) and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.
Purchased Power and Fuel Adjustment Clause	PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE We recover actual fuel, purchased power and transmission costs to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); 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 Renewable Energy Standard (RES) requires TEP to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements in 2025 , with distributed generation accounting for 30% of the annual renewable energy requirement. TEP must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out this plan is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates. TEP is required to implement cost-effective Demand Side Management (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 Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through Renewable Energy Credits (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. 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 our balance sheets. 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. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that 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. Prior to 1990, TEP flowed through to ratepayers 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 ratepayers as these tax benefits reverse. See Note 2 for additional information regarding regulatory matters. We account 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 – Noncurrent 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 regulatory assets. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises. Income tax liabilities are allocated to TEP based on its taxable income as reported in the FortisUS Inc. consolidated tax return.
Taxes Other Than Income Taxes	TAXES OTHER THAN INCOME TAXES We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies on 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 We use 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 our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the Consolidated Balance Sheets and measure those instruments 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 our derivatives designated as hedging contracts, we formally assess, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, we formally document hedging activity by transaction type and risk management strategy. For our 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 RETIREE BENEFITS We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees. We recognize the underfunded status of our defined benefit pension plans as a liability on our 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. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees. Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate 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, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance For Doubtful Accounts	The change in the balance of the Allowance for Doubtful Accounts in our Consolidated Balance Sheets is summarized as follows: Year Ended December 31, (in millions) 2015 2014 2013 Beginning of Period $ 5 $ 5 $ 5 Increases: Charged to Operating Revenues 23 — — Charged to Operating Expenses 2 2 2 Write-offs (3 ) (2 ) (2 ) End of Period $ 27 $ 5 $ 5
AFUDC Rates	The average AFUDC rates on regulated construction expenditures are included in the table below: 2015 2014 2013 Average AFUDC Rates 6.12 % 7.30 % 7.38 %
Summary Of Average Annual Depreciation Rates For All Utility Plants	Below are the summarized average annual depreciation rates for all utility plant: 2015 2014 2013 Average Annual Depreciation Rates 2.83 % 2.99 % 3.16 %

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Schedule of Purchased Power and Fuel Adjustment Rates	The PPFAC rates during the periods reported were as follows: Period Cents per kWh April 2015 through March 2016 0.68 October 2014 through March 2015 (1) 0.50 May 2014 through September 2014 (1) 0.10 July 2013 through April 2014 (2) (0.14 ) January 2013 through June 2013 0.77 (1) The ACC approved a two-step increase to shift a higher level of recovery into the winter season. (2) The effective date of the 2012 PPFAC rate reduction was deferred to coincide with the effective date of the 2013 Rate Order.
Schedule of Regulatory Assets and Liabilities	Regulatory assets and liabilities recorded on the Consolidated Balance Sheets are summarized below: December 31, (in millions) 2015 2014 Regulatory Assets Pension and Other Retiree Benefits (Note 8) $ 120 $ 126 Final Mine Reclamation and Retiree Health Care Costs (1) 28 29 Income Taxes Recoverable through Future Rates (2) 26 31 Property Tax Deferrals (3) 21 21 Springerville Unit 1 Leasehold Improvements - Third Party Owners (4) 21 — LFCR and DSM 16 12 Derivatives (Note 11) 12 18 PPFAC — 19 Springerville Purchase Deferrals (5) — 16 Other Regulatory Assets 20 20 Total Regulatory Assets 264 292 Less Current Portion 52 69 Total Non-Current Regulatory Assets $ 212 $ 223 Regulatory Liabilities Net Cost of Removal for Interim Retirements (6) $ 264 $ 265 Deferred Investment Tax Credits (7) 32 41 RES 25 28 PPFAC 18 — Other Regulatory Liabilities 21 26 Total Regulatory Liabilities 360 360 Less Current Portion 53 39 Total Non-Current Regulatory Liabilities $ 307 $ 321 (1) 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 has the option to recognize its liability associated with final reclamation and retiree health care obligations at present or future value. TEP has elected to recognize these costs at future value and is permitted to fully recover these costs through the PPFAC when paid. TEP expects to make continuous payments through 2037 . (2) 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. (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) Upon expiration of Springerville Unit 1 capital leases in January 2015, TEP recorded a regulatory asset for unamortized leasehold improvement costs that relate to third-party ownership interests. These leasehold improvements, previously recorded in Plant in Service on the Consolidated Balance Sheets, represent investments TEP made through the end of the lease term to ensure that the Springerville Unit 1 facilities continued providing safe, reliable service to TEP's customers. In the 2013 Rate Order, TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10-year amortization period. (5) TEP deferred the increase in lease interest expense relating to the purchase commitments for Springerville Unit 1 and the Springerville Coal Handling Facilities to a regulatory asset because TEP believes the full purchase price is recoverable in rate base. See Note 6 for additional information regarding the Springerville leases. (6) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations 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 Credit (ITC) represents 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, 2015
Regulated Operations [Abstract]
Public Utility Property, Plant, and Equipment	The following table shows Utility Plant in Service by major class: December 31, (in millions) 2015 2014 Plant in Service Electric Generation Plant $ 2,612 $ 2,388 Electric Transmission Plant 1,008 890 Electric Distribution Plant 1,456 1,398 General Plant 358 338 Intangible Plant - Software Costs (1) (2) 172 149 Intangible Plant - Transmission Rights and Other 7 8 Electric Plant Held for Future Use 5 4 Total Plant in Service $ 5,618 $ 5,175 Utility Plant under Capital Leases (3) $ 132 $ 667 (1) Unamortized computer software costs were $45 million and $31 million as of December 31, 2015 and 2014 , respectively. (2) The amortization of computer software costs was $14 million in 2015 , $17 million in 2014 , and $14 million in 2013 . (3) TEP purchased certain Springerville facilities leased interests in 2015 and 2014. See Note 6 for additional information regarding the Springerville leases.
Amount Of Lease Expense Incurred Related Capital Leases	The following table shows the amount of lease expense incurred for generation-related capital leases: Year Ended December 31, (in millions) 2015 2014 2013 Lease Expense Interest Expense – Included in: Capital Leases $ 4 $ 10 $ 25 Operating Expenses – Fuel — 1 2 Amortization of Capital Lease Assets – Included in: Operating Expenses – Fuel 2 6 5 Operating Expenses – Amortization 6 16 15 Total Lease Expense $ 12 $ 33 $ 47
Depreciable Lives Of Utility Plant In Service	Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available for the major classes of Utility Plant in Service at December 31, 2015 , were as follows: Annual Depreciation Rate (1) Average Remaining Life in Years Electric Generation Plant 3.31% 22 Electric Transmission Plant 1.48% 32 Electric Distribution Plant 2.08% 35 General Plant 5.48% 11 Intangible Plant (2) Various Various (1) The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant. (2) The majority of TEP's investment in intangible plant represents computer software. Computer software is being amortized over its expected useful life of three to five years for smaller application software and average remaining life of three to eight years for large enterprise software.
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the assets acquired and liabilities assumed as of the acquisition date: (in millions) Utility Plant, Net $ 163 Materials and Supplies 2 ARO Obligation Assumed (1) (1 ) Total Purchase Price $ 164 (1) The ARO obligation was recorded at net present value in Regulatory and Other Liabilities - Other on TEP's Consolidated Balance Sheets.
Schedule of Jointly Owned Utility Plants	In addition to Gila River Unit 3, at December 31, 2015 , TEP was a participant in the following jointly-owned generating stations 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% $ 486 $ 12 $ 251 $ 247 Navajo Units 1, 2, and 3 7.5% 148 2 112 38 Four Corners Units 4 and 5 7.0% 102 9 77 34 Luna Energy Facility 33.3% 54 — — 54 Gila River Unit 3 75.0% 198 2 56 144 Gila River Common Facilities 18.8% 25 — 7 18 Springerville Unit 1 (1) 49.5% 319 8 174 153 Springerville Coal Handling Facility (2) 65.9% 164 1 65 100 Transmission Facilities Various 383 1 172 212 Total $ 1,879 $ 35 $ 914 $ 1,000 (1) TEP is obligated to operate the unit for the Third-Party Owners under existing agreements. The Owner Trustees and Co-Trustees are obligated to compensate TEP for their pro rata share of expenses. See Note 6 for additional information regarding the purchase of leased interest. See Note 7 for additional information regarding Springerville Unit 1. (2) TEP owns an additional 17.05% undivided interest in the Springerville Coal Handling Facilities classified as Assets Held for Sale 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 on the Consolidated Balance Sheets: December 31, (in millions) 2015 2014 Beginning of Period $ 28 $ 22 Liabilities Incurred 4 5 Accretion Expense or Regulatory Deferral 1 1 Revisions to the Present Value of Estimated Cash Flows (1) (1 ) — End of Period $ 32 $ 28 (1) Primarily related to changes in expected cost estimates, in conjunction with changes of asset retirement dates of generating facilities.

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 Customer $ 79 $ 78 Due from Affiliates (Note 5) 7 5 Unbilled 39 37 Other 39 17 Allowance for Doubtful Accounts (1) (27 ) (5 ) Accounts Receivable, Net $ 137 $ 132 (1) The Allowance for Doubtful Accounts increased in 2015 due to the Third-Party Owners' claims at Springerville Unit 1. See Note 7 for additional information regarding the Third-Party Owners' claims.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Table)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 Receivables from Related Parties UNS Electric $ 6 $ 4 UNS Gas 1 1 Total Due from Related Parties $ 7 $ 5 Payables to Related Parties SES $ 2 $ 2 UNS Electric 2 1 UNS Energy 2 — Total Due to Related Parties $ 6 $ 3 The following table presents the components of related party transactions included on the Consolidated Statements of Income: Year Ended December 31, (in millions) 2015 2014 2013 Wholesale Sales - TEP to UNS Electric (1) $ 8 $ 4 $ 1 Wholesale Sales - UNS Electric to TEP (1) 1 4 2 Control Area Services - TEP to UNS Electric (2) 2 3 4 Common Costs - TEP to UNS Energy Affiliates (3) 12 13 12 Supplemental Workforce - SES to TEP (4) 16 16 16 Corporate Services - UNS Energy to TEP (5) 7 14 5 Corporate Services - UNS Energy Affiliates to TEP (6) 1 1 1 (1) TEP and UNS Electric sell power and transmission services to each other at prevailing market prices. (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 include Fortis management fees, legal fees, and audit fees which 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 81% of UNS Energy's allocated costs. In 2015 , these costs included approximately $5 million in Fortis management fees, which began in January 2015 following the August 2014 acquisition. In 2014 , these costs included approximately $12 million in acquisition-related costs (excluding TEP allocated labor related charges). (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 FACILITIES, AND 29

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	LONG-TERM 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 on the Consolidated Balance Sheets: (dollars in millions) December 31, Debt (1) Interest Rate Maturity Date (3) 2015 2014 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 — Tax Exempt Local Furnishings Bonds 1982 Pima A Irvington Project Reset Weekly (2) 2022 — 39 1982 Pima A TEP Projects Reset Weekly (2) 2022 — 40 2008 Pima B 5.75% 2029 — 130 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 Reset Monthly (2) 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 Reset Weekly (2) 2032 37 37 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt 1,466 1,375 Less Unamortized Discount and Debt Issuance Costs 14 13 Total Long-Term Debt, Net $ 1,452 $ 1,362 (1) As of December 31, 2015 , all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by a LOC. (2) For variable rate debt for which rates are reset weekly, the weighted average rate (including LOC fees and remarketing fees) was 1.24% in 2015 and 1.46% in 2014 . The average weekly interest rate ranged from 0.93% - 1.42% in 2015 and 1.40% - 1.75% during 2014 . For variable rate debt for which rates are reset monthly, the rate is based on a percentage of an index equal to one-month London Interbank Offered Rate (LIBOR) plus a credit spread. The average monthly rate was 0.81% in 2015 and 0.87% in 2014 . The monthly interest rate ranged from 0.79% - 0.87% in 2015 and 0.85% - 0.95% in 2014 . (3) The 2010 Coconino A variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. The 2013 Apache A variable rate bonds are subject to mandatory tender for purchase in 2018.
Schedule of Capital Lease Obligations [Table Text Block]	CAPITAL LEASE OBLIGATIONS The following table details Capital Lease Obligation on TEP's Consolidated Balance Sheets: December 31, (in millions) 2015 2014 Springerville Unit 1 $ — $ 43 Springerville Coal Handling Facilities — 117 Springerville Common Facilities 69 83 Total Capital Lease Obligations 69 243 Less Current Obligations Under Capital Leases 14 174 Total Capital Lease Obligations, Net $ 55 $ 69
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 Maturities (1) Capital Lease Obligations Total (2) 2016 $ — $ 15 $ 15 2017 — 16 16 2018 100 11 111 2019 37 11 48 2020 80 18 98 Total 2016 - 2020 217 71 288 Thereafter 1,249 — 1,249 Less: Imputed Interest — (2 ) (2 ) Total $ 1,466 $ 69 $ 1,535 (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 is not reduced by $11 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, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments	At December 31, 2015 , TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases: (in millions) 2016 2017 2018 2019 2020 Thereafter Total Fuel, Including Transportation $ 78 $ 76 $ 49 $ 49 $ 41 $ 287 $ 580 Purchased Power 28 — — — — — 28 Transmission 6 6 6 4 3 13 38 Renewable Power Purchase Agreements 61 61 61 61 60 750 1,054 RES Performance-Based Incentives 8 8 8 8 8 67 107 Operating Leases: Land Easements and Rights-of-Way 1 1 1 1 1 77 82 Operating Leases Other 1 1 1 1 1 4 9 Total Purchase Commitments $ 183 $ 153 $ 126 $ 124 $ 114 $ 1,198 $ 1,898

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Schedule of Amounts Recognized in Balance Sheet	The following table summarizes pension and other retiree benefit related amounts (excluding tax balances) included on the Consolidated Balance Sheets: Pension Benefits Other Retiree Benefits December 31, (in millions) 2015 2014 2015 2014 Regulatory Pension Asset Included in Regulatory Assets $ 115 $ 117 $ 5 $ 9 Accrued Benefit Liability Included in Accrued Employee Expenses (1 ) (1 ) (2 ) (2 ) Accrued Benefit Liability Included in Pension and Other Retiree Benefits (57 ) (71 ) (63 ) (67 ) Accumulated Other Comprehensive Loss (related to SERP) 5 5 — — Net Amount Recognized $ 62 $ 50 $ (60 ) $ (60 )
Schedule of Changes in Funded Status	The status of our pension benefit and other retiree benefit plans are summarized below: Pension Benefits Other Retiree Benefits Year Ended December 31, (in millions) 2015 2014 2015 2014 Change in Projected Benefit Obligation Benefit Obligation at Beginning of Year $ 407 $ 330 $ 81 $ 74 Actuarial (Gain) Loss (22 ) 67 (5 ) 5 Interest Cost 17 16 3 3 Service Cost 12 10 4 4 Benefits Paid (20 ) (16 ) (5 ) (5 ) Projected Benefit Obligation at End of Year 394 407 78 81 Change in Plan Assets Fair Value of Plan Assets at Beginning of Year 335 307 12 10 Actual Return on Plan Assets (3 ) 35 — 1 Benefits Paid (20 ) (16 ) (5 ) (5 ) Employer Contributions (1) 24 9 6 6 Fair Value of Plan Assets at End of Year 336 335 13 12 Funded Status at End of Year $ (58 ) $ (72 ) $ (65 ) $ (69 ) (1) In 2016 , TEP expects to contribute $10 million to the pension plans.
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 Retiree Benefits Year Ended December 31, (in millions) 2015 2014 2015 2014 Net Loss $ 117 $ 118 $ 6 $ 11 Prior Service Cost (Benefit) 3 4 (1 ) (2 )
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) 2015 2014 Accumulated Benefit Obligation $ 188 $ 365 Fair Value of Plan Assets 169 335
Components of Net Periodic Benefit Cost	Net periodic benefit plan cost includes the following components: Pension Benefits Other Retiree Benefits Year Ended December 31, (in millions) 2015 2014 2013 2015 2014 2013 Service Cost $ 12 $ 10 $ 11 $ 4 $ 4 $ 3 Interest Cost 17 16 14 3 3 3 Expected Return on Plan Assets (23 ) (21 ) (19 ) (1 ) (1 ) (1 ) Actuarial Loss Amortization 7 3 8 — — — Net Periodic Benefit Cost $ 13 $ 8 $ 14 $ 6 $ 6 $ 5
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 Regulatory Asset AOCI (in millions) 2015 2014 2013 2015 2014 2013 Current Year Actuarial (Gain) Loss $ 5 $ 49 $ (42 ) $ — $ 3 $ (1 ) Amortization of Actuarial Gain (Loss) (7 ) (3 ) (8 ) — — — Total Recognized (Gain) Loss $ (2 ) $ 46 $ (50 ) $ — $ 3 $ (1 ) Other Retiree Benefits Regulatory Asset (in millions) 2015 2014 2013 Current Year Actuarial (Gain) Loss $ (4 ) $ 5 $ (6 )
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 Retiree Benefits 2015 2014 2015 2014 Discount Rate 4.5-4.6% 4.1-4.2% 4.2% 3.9% Rate of Compensation Increase 3.0% 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 Retiree Benefits 2015 2014 2013 2015 2014 2013 Discount Rate 4.1%-4.2% 5.0%-5.1% 4.1%-4.1% 3.9% 4.7% 3.8% 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	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. The following table includes the assumed health care cost trend rates: December 31, 2015 2014 Next Year 7.6% 6.7% Ultimate Rate Assumed 4.5% 4.5% Year Ultimate Rate is Reached 2036 2027
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 December 31, 2015 amounts: (in millions) One-Percentage- Point Increase One-Percentage- Point Decrease Effect on Total Service and Interest Cost Components $ 1 $ 1 Effect on Retiree Benefit Obligation 6 5
Schedule of Allocation of Plan Assets	Pension plan asset allocations, by asset category, on the measurement date were as follows: 2015 2014 Asset Category Equity Securities 49 % 48 % Fixed Income Securities 41 % 43 % Real Estate 8 % 7 % Other 2 % 2 % Total 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: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (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 (in millions) December 31, 2014 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 82 — 82 United States Small Cap — 17 — 17 Non-United States — 61 — 61 Fixed Income — 143 — 143 Real Estate — 8 16 24 Private Equity — — 7 7 Total $ 1 $ 311 $ 23 $ 335 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 Beginning Balance at January 1, 2014 $ 7 $ 14 $ 21 Actual Return on Plan Assets: Assets Held at Reporting Date 1 2 3 Purchases, Sales, and Settlements (1 ) — (1 ) Ending Balance at 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 ) Ending Balance at December 31, 2015 $ 7 $ 18 $ 25
Target Allocation Percentages for Plan Assets	The current target allocation percentages for the major asset categories of the plan as of December 31, 2015 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced. TEP Plans VEBA Trust Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 24% 39% United States Small Cap 5% 5% Non-United States Developed 15% 7% Non-United States Emerging 5% 9% 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 retiree benefit plan, which reflect future service, as appropriate. (in millions) 2016 2017 2018 2019 2020 2021-2025 Pension Benefits $ 17 $ 18 $ 19 $ 21 $ 22 $ 125 Other Retiree Benefits 5 5 5 6 6 33

SUPPLEMENTAL CASH FLOW INFORM32

SUPPLEMENTAL CASH FLOW INFORMATION SUPPLEMENTAL CASH FLOW (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	CASH TRANSACTIONS Year Ended December 31, (in millions) 2015 2014 2013 Interest, Net of Amounts Capitalized $ 65 $ 83 $ 53 Income Taxes — — — 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: Year Ended December 31, (in millions) 2015 2014 2013 Accrued Capital Expenditures $ 28 $ 29 $ 24 Net Cost of Removal of Interim Retirements (1) 1 12 25 Commitment to Purchase Capital Lease Interests — 109 55 Capital Lease Obligations (2) — 1 9 Proceeds from Issuance of Long-Term Debt Deposited in Trust — — 191 Asset Retirement Obligations (3) 3 4 8 (1) The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations 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 asset retirement obligations and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future asset retirement obligations.

FAIR VALUE MEASUREMENTS AND D33

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
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, 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 (in millions) December 31, 2014 Assets Cash Equivalents (1) $ 15 $ — $ — $ 15 Restricted Cash (1) 2 — — 2 Energy Derivative Contracts - Regulatory Recovery (2) — — 2 2 Total Assets 17 — 2 19 Liabilities Energy Derivative Contracts - Regulatory Recovery (2) — (9 ) (9 ) (18 ) Energy Derivative Contracts - No Regulatory Recovery (2) — — (1 ) (1 ) Energy Derivative Contracts - Cash Flow Hedge (2) — — (1 ) (1 ) Interest Rate Swap (3) — (5 ) — (5 ) Total Liabilities — (14 ) (11 ) (25 ) Net Total Assets (Liabilities) $ 17 $ (14 ) $ (9 ) $ (6 ) (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), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014 a power sale option (Level 3). 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 Counterparty Netting and Cash Collateral	All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We present derivatives on a gross basis on the balance sheet. The tables below presents the potential offset of counterparty netting and cash collateral. Gross Amount Recognized on the Balance Sheets Gross Amount Not Offset on the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (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 ) (in millions) December 31, 2014 Derivative Assets Energy Derivative Contracts $ 2 $ 2 $ — $ — Derivative Liabilities Energy Derivative Contracts (20 ) (2 ) — (18 ) Interest Rate Swap (5 ) — — (5 )
Realized Losses from Cash Flow Hedges	The realized losses from our cash flow hedges are shown in the following table: Year Ended December 31, (in millions) 2015 2014 2013 Capital Lease Interest Expense $ 2 $ 2 $ 2 Long-Term Debt Interest Expense — 1 1 Purchased Power 1 1 1
Financial Impact of Energy Contracts	Energy Derivative Contracts - Regulatory Recovery We record 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: Year Ended December 31, (in millions) 2015 2014 2013 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ 6 $ (18 ) $ —
Derivative Volumes	Derivative Volumes At December 31, 2015 , we have energy contracts that will settle through the fourth quarter of 2018 . The volumes associated with our energy contracts were as follows: December 31, 2015 2014 Power Contracts GWh 1,752 2,604 Gas Contracts GBtu 17,214 19,932
Level 3 Fair Value Quantitative Information Regarding Unobservable Inputs	Level 3 Fair Value Measurements The following table provides 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, 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 ) (in millions) December 31, 2014 Forward Power Contracts Market approach $ 1 $ (6 ) Market price per MWh $ 22.35 $ 39.05 Power Sale Option Market approach 1 (1 ) Market price per MWh $ 27.75 $ 44.94 Market price per MMbtu $ 2.88 $ 4.02 Gas Option Contracts Option model — (4 ) Market price per MMbtu $ 2.72 $ 3.26 Gas volatility 30.8 % 53.3 % Level 3 Energy Contracts $ 2 $ (11 )
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: Year Ended December 31, (in millions) 2015 2014 Beginning of Period $ (9 ) $ (2 ) Gains (Losses) Recorded to: (1) Net Regulatory Assets/Liabilities – Derivative Instruments (4 ) (8 ) Electric Wholesale Sales 3 — Settlements 8 1 End of Period $ (2 ) $ (9 ) (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 $(8) million for the years ended December 31, 2015, and 2014 , respectively.
Face Value and Estimated Fair Value of Long-Term Debt	The following table includes the face value and estimated fair value of our long-term debt: Fair Value Hierarchy Face Value Fair Value December 31, (in millions) 2015 2014 2015 2014 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,375 $ 1,529 $ 1,457

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
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: Year Ended December 31, (in millions) 2015 2014 2013 Federal Income Tax Expense at Statutory Rate $ 70 $ 56 $ 52 State Income Tax Expense, Net of Federal Deduction 8 7 7 Federal/State Tax Credits (8 ) (5 ) (2 ) Allowance for Equity Funds Used During Construction (1 ) (2 ) (1 ) Deferred Tax Asset Valuation Allowance 1 — 2 Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset — — (11 ) Other 2 2 1 Total Federal and State Income Tax Expense $ 72 $ 58 $ 48
Schedule Of Income Tax Reconciliation Table	Income tax expense included in the income statements consists of the following: Year Ended December 31, (in millions) 2015 2014 2013 Current Tax Expense (Benefit) Federal $ — $ (1 ) $ (8 ) State — — (2 ) Total Current Tax Expense (Benefit) — (1 ) (10 ) Deferred Tax Expense (Benefit) Federal 66 54 47 Federal Investment Tax Credits (6 ) (4 ) (1 ) State 12 9 12 Total Deferred Tax Expense (Benefit) 72 59 58 Total Federal and State Income Tax Expense $ 72 $ 58 $ 48
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) 2015 2014 Gross Deferred Income Tax Assets Capital Lease Obligations $ 27 $ 96 Net Operating Loss Carryforwards 156 187 Customer Advances and Contributions in Aid of Construction 20 19 Alternative Minimum Tax Credit 24 24 Accrued Postretirement Benefits 23 23 Emission Allowance Inventory 9 10 Investment Tax Credit Carryforward 32 31 Other 53 54 Total Gross Deferred Income Tax Assets 344 444 Deferred Tax Assets Valuation Allowance (4 ) (2 ) Gross Deferred Income Tax Liabilities Plant, Net (750 ) (699 ) Capital Lease Assets, Net (12 ) (74 ) Pensions (27 ) (27 ) PPFAC — (8 ) Other (19 ) (24 ) Total Gross Deferred Income Tax Liabilities (808 ) (832 ) Net Deferred Income Tax Liabilities $ (468 ) $ (390 )
Summary Of Details Of Tax Carryforwards Table	As of December 31, 2015 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 430 2031-34 State Net Operating Loss 114 2016-34 State Credits 10 2016-30 Alternative Minimum Tax Credit 24 None Investment Tax Credits 32 2032-35
Summary of Income Tax Contingencies	A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2015 2014 Beginning of Period $ 4 $ 2 Additions Based on Tax Positions Taken in the Current Year 1 2 End of Period $ 5 $ 4

QUARTERLY FINANCIAL DATA (Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 Operating Revenue $ 273 $ 340 $ 409 $ 284 Operating Income 28 74 120 36 Net Income 9 38 69 12 (in millions) 2014 Operating Revenue $ 256 $ 322 $ 387 $ 305 Operating Income 32 80 85 34 Net Income 9 39 40 15

NATURE OF OPERATIONS AND SUMM36

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Detail) customer in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)mi²customer	Dec. 31, 2014USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Retail customers | customer	417
Area in which subsidiary generates transmits and distributes electricity to retail electric customers | mi²	1,155
Restricted Cash and Cash Equivalents, Noncurrent | $	$ 4	$ 2

NATURE OF OPERATIONS AND SUMM37

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Fortis Acquisition of UNS Energy) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 15, 2014
Percent of Income Restriction on Payment of Dividends		60.00%
Length in Periods of Restrictions On Payment Of Dividends (in Years)		5 years
Required Equity Capitalization for Regulated Utilities Prior to Dividend Payment		50.00%
Required Equity Investment By Acquiring Company Per Merger Settlement Agreement With Regulatory Approval				$ 220,000
Contribution To Parent of Filer		$ 287,000
Contribution from Parent	$ 180,000	225,000	$ 0
Allocated Share of Acquisition-Related Expenses		15,000
Total Bill Credit Refunds Over 5 Years [Member]
Fortis Acquisition Customer Bill Credits		$ 19,000
Years Over Which Fortis Acquisition Bill Credit Are Paid		5 years
Bill Credit Refunds in Year 1 [Member]
Fortis Acquisition Customer Bill Credits		$ 6,000
Annual Bill Credit Refunds in Years 2 Through 5 [Member]
Fortis Acquisition Customer Bill Credits		3,000
Fortis Inc. [Member]
Fortis Acquisition of UNS Energy, Share Price				$ 60.25
UNS Energy to TEP [Member]
Contribution from Parent		$ 225,000

NATURE OF OPERATIONS AND SUMM38

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Recently Adopted Accounting Pronouncements) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred Income Taxes, Net	$ 468,024	$ 389,540
New Accounting Pronouncement, Early Adoption, Effect [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred tax assets, current		102,000
Deferred Income Taxes, Net		(102,000)
Other Assets [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred financing costs, reclassified		(11,000)
Long-term Debt [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred financing costs, reclassified		$ 11,000

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts Disclosure [Line Items]
Allowance for Doubtful Accounts	$ 5	$ 5	$ 5
Increases Charged to Operating Revenues	23	0	0
Increases Charged to Operating Expenses	2	2	2
Write-offs	(3)	(2)	(2)
Allowance for Doubtful Accounts	$ 27	$ 5	$ 5

NATURE OF OPERATIONS AND SUMM40

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average AFUDC Rates	6.12%	7.30%	7.38%

NATURE OF OPERATIONS AND SUMM41

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average annual depreciation rate	2.83%	2.99%	3.16%

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, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Renewable Energy Target Percentage by 2025	15.00%
Distributed Generation Requirement Target Percentage	30.00%

REGULATORY MATTERS (Rate Case)

REGULATORY MATTERS (Rate Case) (Details) - Arizona Corporation Commission [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Public Utilities, General Disclosures [Line Items]
Requested Rate Increase Amount to Cover Revenue Deficiency	$ 110
Requested Return on Original Cost Rate Base Increase, Percentage	12.00%
Requested Return on Original Cost Rate Base, Percentage	7.34%
Original Cost Rate Base	$ 2,100

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 29, 2016USD ($)	Jul. 31, 2015USD ($)	Dec. 31, 2025	Dec. 31, 2020	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / MWh	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage						15.00%
Distributed Generation Requirement Target Percentage						30.00%
Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Over-Recovered Costs for Purchased Power and Fuel						$ 18
Under-Recovered Costs for Purchased Power and Fuel							$ 19
2013 TEP Rate Order [Member] | San Juan [Member] | Fire [Member]
Public Utilities, General Disclosures [Line Items]
Mine Fire Cost Deferral							10
Insurance Proceeds Received to Date						1	8
Unreimbursed Fuel Costs						$ 1
Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage						5.00%
Renewable Energy Budget Spending		$ 57
Renewable Energy Unused Fund Carryover		9
Approved Renewable Energy Budget		$ 48
Renewable Energy Program [Member] | Scenario, Forecast [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage			15.00%		6.00%
Distributed Generation Requirement Target Percentage			30.00%
Recovery Revenue					$ 9
Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Percentage of Cumulative Annual Retail Kilowatt Savings, Actual						9.30%
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]
Energy Efficiency Performance Incentive						$ 3	2	$ 1
Lost Fixed Cost Recovery Mechanism - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue						$ 12	$ 11	$ 2
Cap on Increase in Lost Fixed Cost Recovery Rate						1.00%
Effective April 2015 Through March 2016 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / MWh						0.0068
Effective October 2014 through March 2015 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / MWh						0.0050
Effective May 2014 through September 2014 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / MWh						0.0010
Effective July 2013 through April 2014 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / MWh						(0.0014)
January 2013 through June 2013 [Member] | Purchased Power and Fuel Adjustment Clause [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [cents per kwh] | $ / MWh						0.0077
Subsequent Event [Member] | Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Approved Recovery of Spending Budget	$ 14

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Assets) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 264,000	$ 292,000
Less Current Portion	51,841	69,383
Total Non-Current Regulatory Assets	212,312	223,192
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	120,000	126,000
Final Mine Reclamation and Retiree Health Care Costs [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	28,000	29,000
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	26,000	31,000
Property Tax Deferrals [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	21,000	21,000
Springerville Unit 1 Leasehold Improvements - Third Party Owners [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	21,000	0
Lost Fixed Cost Recovery and Demand Side Management [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	16,000	12,000
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	12,000	18,000
Purchased Power and Fuel Adjustment Clause [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	0	19,000
Springerville Deferrals [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	0	16,000
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 20,000	$ 20,000

REGULATORY MATTERS REGULATORY M

REGULATORY MATTERS REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 360,000	$ 360,000
Regulatory Liabilities	53,077	38,847
Regulatory Liabilities	307,286	321,186
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	264,000	265,000
Deferred Investment Tax Credit [Member]
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	32,000	41,000
Renewable Energy Program [Member]
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	25,000	28,000
Purchased Power and Fuel Adjustment Clause [Member]
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	18,000	0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 21,000	$ 26,000

UTILITY PLANT AND JOINTLY-OWN47

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Plant in Service:
Total Plant in Service	$ 5,618,435	$ 5,175,148
Utility Plant Under Capital Leases	131,705	667,157
Electricity Generation Plant, Non-Nuclear [Member]
Plant in Service:
Total Plant in Service	2,612,000	2,388,000
Electric Transmission Plant [Member]
Plant in Service:
Total Plant in Service	1,008,000	890,000
Electric Distribution Plant [Member]
Plant in Service:
Total Plant in Service	1,456,000	1,398,000
General Plant [Member]
Plant in Service:
Total Plant in Service	358,000	338,000
Software Costs [Member]
Plant in Service:
Total Plant in Service	172,000	149,000
Property, Plant and Equipment, Other Types [Member]
Plant in Service:
Total Plant in Service	7,000	8,000
Electric Plant Held for Future Use [Member]
Plant in Service:
Total Plant in Service	$ 5,000	$ 4,000

UTILITY PLANT AND JOINTLY-OWN48

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class Footnotes) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulated Operations [Abstract]
Capitalized Computer Software, Net	$ 45	$ 31
Amortization of computer software costs	$ 14	$ 17	$ 14

UTILITY PLANT AND JOINTLY-OWN49

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for TEP's Generation-Related Capital Leases) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Capital Lease Expense	$ 12	$ 33	$ 47
Interest Expense [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Interest Expense	4	10	25
Operating Expenses Fuel [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Interest Expense	0	1	2
Amortization of Capital Lease Assets	2	6	5
Operating Expenses Depreciation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Amortization of Capital Lease Assets	$ 6	$ 16	$ 15

UTILITY PLANT AND JOINTLY-OWN50

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.83%	2.99%	3.16%
Electric Generation Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation Plant	22 years
Depreciation Rate	3.31%
Electric Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission Plant	32 years
Depreciation Rate	1.48%
Electric Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution Plant	35 years
Depreciation Rate	2.08%
General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
General Plant	11 years
Depreciation Rate	5.48%

UTILITY PLANT AND JOINTLY-OWN51

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service Footnotes) (Details)	12 Months Ended
	Dec. 31, 2015
Minimum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	3 years
Minimum [Member] | Other Intangible Assets [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	3 years
Maximum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	5 years
Maximum [Member] | Other Intangible Assets [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	8 years

UTILITY PLANT AND JOINTLY-OWN52

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Acquisition) (Details) $ in Millions	Dec. 31, 2014USD ($)MW
Springerville Unit One [Member]
Unusual or Infrequent Item [Line Items]
Generating Capacity of Plant in MW | MW	195
San Juan Unit Two [Member]
Unusual or Infrequent Item [Line Items]
Generating Capacity of Plant in MW | MW	170
Entegra, Gila River Generating Station Unit 3 [Member]
Unusual or Infrequent Item [Line Items]
Generating Capacity of Plant in MW | MW	550
PURCHASE PRICE FOR UTILITY PLANT NET	$ 163
Purchase Price for Materials and Supplies	2
Purchase Price for ARO Obligation Assumed	(1)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 164
Entegra, Gila River Generating Station Unit 3 [Member] | Tucson Electric Power Company To Uns Electric [Member]
Unusual or Infrequent Item [Line Items]
Generating Capacity of Plant in MW | MW	413
Percentage Of Ownership In Generating Units	75.00%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 164
Entegra, Gila River Generating Station Unit 3 [Member] | Uns Electric To Tucson Electric Power Company [Member]
Unusual or Infrequent Item [Line Items]
Percentage Of Ownership In Generating Units	25.00%

UTILITY PLANT AND JOINTLY-OWN53

UTILITY PLANT AND JOINTLY-OWNED FACILITES (TEP's Interests in Jointly-Owned Generating Stations and Transmission Systems) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$ 1,879
Construction Work in Progress	35
Accumulated Depreciation	914
Net Book Value	$ 1,000
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	$ 486
Construction Work in Progress	12
Accumulated Depreciation	251
Net Book Value	$ 247
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	$ 148
Construction Work in Progress	2
Accumulated Depreciation	112
Net Book Value	$ 38
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	$ 102
Construction Work in Progress	9
Accumulated Depreciation	77
Net Book Value	$ 34
Luna Energy Facility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	33.30%
Plant in Service	$ 54
Construction Work in Progress	0
Accumulated Depreciation	0
Net Book Value	$ 54
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	$ 198
Construction Work in Progress	2
Accumulated Depreciation	56
Net Book Value	$ 144
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	7
Net Book Value	$ 18
Springerville Unit One [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	49.50%
Plant in Service	$ 319
Construction Work in Progress	8
Accumulated Depreciation	174
Net Book Value	$ 153
Springerville Coal Handling Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	65.90%
Plant in Service	$ 164
Construction Work in Progress	1
Accumulated Depreciation	65
Net Book Value	$ 100
Utility Plant, Proportionate Ownership Share Held for Sale	17.05%
Transmission Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$ 383
Construction Work in Progress	1
Accumulated Depreciation	172
Net Book Value	$ 212

UTILITY PLANT AND JOINTLY-OWN54

UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Retirements) (Details) $ in Millions	Dec. 31, 2015USD ($)
Jointly Owned Utility Plant, Net Ownership Amount	$ 1,000
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	$ 104

UTILITY PLANT AND JOINTLY-OWN55

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Asset Retirement Obligations) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulated Operations [Abstract]
Beginning Balance	$ 28	$ 22
Asset Retirement Obligation, Liabilities Incurred	4	5
Accretion Expense	1	1
Revision to Estimated Cash Flows	(1)	0
Ending Balance	$ 32	$ 28

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable, Net [Abstract]
Customer	$ 79,000	$ 78,000
Due from Affiliates (Note 5)	7,000	5,000
Unbilled	39,000	37,000
Other	39,000	17,000
Allowance for Doubtful Accounts (1)	(27,000)	(5,000)
Accounts Receivable, Net	$ 136,682	$ 131,799

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction, Due from (to) Related Parties [Abstract]
Due from Affiliates (Note 5)	$ 7,000,000	$ 5,000,000
Accounts Payable, Related Parties, Current	6,000,000	3,000,000
Business Acquisition, Transaction Costs		15,000,000
Contribution from Parent	180,000,000	225,000,000	$ 0
Dividends Paid to Parent	50,000,000	40,000,000	40,000,000
Dividends Declared to Parent	$ 50,000,000	$ 40,000,000	40,000,000
Percent of Income Restriction on Payment of Dividends		60.00%
Required Equity Investment By Acquiring Company Per Merger Settlement Agreement		50.00%
Less Than, Actual Equity Capitalization for Regulated Utilities	50.00%
Tucson Electric Power Company To Uns Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Wholesale Sales from Related Parties	$ 8,000,000	$ 4,000,000	1,000,000
Control Area Services, Other Revenues from Transactions with Related Parties	2,000,000	3,000,000	4,000,000
Uns Electric To Tucson Electric Power Company [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Wholesale Purchases from Related Parties	1,000,000	4,000,000	2,000,000
TEP to UNS Energy Affiliates [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Common Costs Charged to Related Parties	12,000,000	13,000,000	12,000,000
Southwest Energy Solutions, Inc. to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Supplemental Workforce, Maintenance Costs	16,000,000	16,000,000	16,000,000
UNS Energy Affiliates to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services and Other Labor Charges	1,000,000	1,000,000	1,000,000
UNS Energy to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services and Other Labor Charges	$ 7,000,000	14,000,000	5,000,000
Intercompany Allocation Parent to Subsidiary	81.00%
management fee	$ 5,000,000
Business Acquisition, Transaction Costs		12,000,000
Contribution from Parent	180,000,000	225,000,000	$ 0
UNS Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Due from Affiliates (Note 5)	6,000,000	4,000,000
Accounts Payable, Related Parties, Current	2,000,000	1,000,000
Uns Gas [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Due from Affiliates (Note 5)	1,000,000	1,000,000
Uns Energy Corporation [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Accounts Payable, Related Parties, Current	2,000,000	0
Southwest Energy Solutions, Inc. [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Accounts Payable, Related Parties, Current	$ 2,000,000	$ 2,000,000

DEBT, CREDIT FACILITIES, AND 58

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Long-term Debt) (Detail) - USD ($)	1 Months Ended
	Aug. 31, 2015	Dec. 31, 2015	Feb. 28, 2015	Jan. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Mar. 31, 2014
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,466,000,000			$ 1,375,000,000
Unamortized Discount and Debt Issuance Costs		14,000,000			13,000,000
Long-Term Debt, Net		$ 1,451,720,000			1,361,828,000
Variable Rate Demand Obligation [Member]
Debt Instrument [Line Items]
Derivative, Amount of Hedged Item						$ 50,000,000
Fixed rate of interest related to interest rate swap						2.40%
Notes 2011 5.15% due 2021 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated 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]
Debt Instrument, Interest Rate, Stated 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]
Debt Instrument, Interest Rate, Stated Percentage		5.00%
Long-term Debt, Gross		$ 150,000,000			150,000,000
Debt Instrument, Face Amount							$ 150,000,000
Notes 2015 3.05% due 2025 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.05%
Long-term Debt, Gross		$ 300,000,000			0
Debt Instrument, Face Amount			$ 300,000,000
Tax Exempt Local Furnishings Bonds 1982 Pima Series A TEP Irvington Project due 2022 Variable Rate [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		0			39,000,000
Tax Exempt Local Furnishings Bonds 1982 Pima Series A TEP Projects due 2022 Variable Rate [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 0			$ 40,000,000
Tax Exempt Local Furnishings Bonds 2008 Pima B due 2029 5.75% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					5.75%
Long-term Debt, Gross					$ 130,000,000
Debt Instrument, Repurchased Face Amount				$ 130,000,000
Tax Exempt Local Furnishings Bonds 2010 Pima A due 2040 5.25% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated 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]
Debt Instrument, Interest Rate, Stated 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]
Debt Instrument, Interest Rate, Stated 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]
Long-term Debt, Gross		$ 100,000,000			$ 100,000,000
Effective interest rate		0.81%			0.87%
Debt Instrument, Face Amount		$ 100,000,000
Tax Exempt Local Furnishings Bonds 2013 Apache A due 2032 Variable Rate [Member] | Minimum [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		0.79%			0.85%
Tax Exempt Local Furnishings Bonds 2013 Apache A due 2032 Variable Rate [Member] | Maximum [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		0.87%			0.95%
Tax Exempt Pollution Control Bonds 2009 Pima A due 2020 4.95% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated 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]
Debt Instrument, Interest Rate, Stated 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]
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]
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Long-term Debt, Gross		$ 177,000,000			$ 177,000,000
Tax Exempt Variable Rate [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		1.24%			1.46%
Debt extinguishment	$ 79,000,000
Tax Exempt Variable Rate [Member] | Minimum [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		0.93%			1.40%
Tax Exempt Variable Rate [Member] | Maximum [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Effective interest rate		1.42%			1.75%

DEBT, CREDIT FACILITIES, AND 59

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Credit agreements) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)credit_extension	Feb. 17, 2016USD ($)	Oct. 31, 2015USD ($)	Dec. 31, 2014USD ($)	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
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			$ 85,000,000
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 LOC Sublimit [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity			50,000,000
Line of Credit [Member] | Revolving Credit Facility 2010 [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity			$ 200,000,000
Line of Credit [Member] | Term Loan [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity				130,000,000
Line of Credit [Member] | Revolving Credit Facility 2014 [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity				$ 70,000,000
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 FACILITIES, AND 60

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Capital Lease) (Details)	1 Months Ended	3 Months Ended	12 Months Ended
	Apr. 30, 2014USD ($)	Mar. 31, 2015	Dec. 31, 2015USD ($)lease	May. 31, 2015USD ($)	Apr. 30, 2015	Jan. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)MW
Debt Instrument [Line Items]
Capital Lease Obligations			$ 69,000,000				$ 243,000,000
Current Obligations Under Capital Leases			14,114,000				173,822,000
Capital Lease Obligations			55,324,000				$ 69,438,000
Generating capacity purchased, in MWs | MW							192
Interest Rate Swap [Member]
Debt Instrument [Line Items]
Notional amount			$ 29,000,000
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%
Notional amount			$ 29,000,000
Notional amount of debt			$ 13,000,000
Derivative basis spread			1.875%				1.75%
Springerville Common Facilities [Member]
Debt Instrument [Line Items]
Capital Lease Obligations			$ 69,000,000				$ 83,000,000
Number of operating lease | lease			2
Term of contract, renewal		2 years
Springerville Unit One Lease [Member]
Debt Instrument [Line Items]
Percentage of interest committed to purchase							0.106
Generating capacity purchased, in MWs | MW						96	41
Lease arrangement, fair market value purchase price						$ 46,000,000	$ 20,000,000
Springerville Coal Handling Facilities Lease [Member]
Debt Instrument [Line Items]
Fixed price to acquire leased interest in facilities	$ 120,000,000
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 Lease [Member] | Tri-State [Member]
Debt Instrument [Line Items]
Sales price of leased interest in facilities				$ 24,000,000
Springerville Common Facility Lease Part One [Member]
Debt Instrument [Line Items]
Fixed price to acquire leased interest in facilities			$ 38,000,000
Springerville Common Facility Lease Part Two [Member]
Debt Instrument [Line Items]
Fixed price to acquire leased interest in facilities			68,000,000
Springerville Unit One [Member]
Debt Instrument [Line Items]
Capital Lease Obligations			$ 0				43,000,000
Percentage of ownership in generating station			49.50%
Springerville Unit One [Member] | Additional Purchase of Equity Interest
Debt Instrument [Line Items]
Percentage of ownership in generating station						24.80%
Springerville Unit One [Member] | Completion of Purchase of Equity Interest [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station						49.50%
Springerville Coal Handling Facilities
Debt Instrument [Line Items]
Capital Lease Obligations			$ 0				$ 117,000,000
Percentage of ownership in generating station			65.90%
Utility Plant, Proportionate Ownership Share Held for Sale			17.05%
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%
Utility Plant, Proportionate Ownership Share Held for Sale			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 station					100.00%

DEBT, CREDIT FACILITIES, AND 61

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt Maturities
2,016	$ 0
2,017	0
2,018	100
2,019	37
2,020	80
Total 2016 - 2020	217
Thereafter	1,249
Less: Imputed Interest	0
Total LT Debt	1,466	$ 1,375
Capital Lease Obligations
2,016	15
2,017	16
2,018	11
2,019	11
2,020	18
Total 2016 - 2020	71
Thereafter	0
Less: Imputed Interest	2
Capital Lease Obligations	69	$ 243
2,016	15
2,017	16
2,018	111
2,019	48
2,020	98
Total 2016 - 2020	288
Thereafter	1,249
Less: Imputed Interest	(2)
Total LT Debt and Capital Lease Obligations	$ 1,535

DEBT, CREDIT FACILITIES, AND 62

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt Footnotes) (Detail)	Dec. 31, 2015USD ($)
Schedule Of Maturities Of Long Term Debt [Line Items]
Unamortized Debt Issuance Expense	$ 11,000,000
Debt discount	3,000,000
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 CONTINGENCIES63

COMMITMENTS AND CONTINGENCIES (COMMITMENTS) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 15, 2016	Jan. 31, 2016
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	$ 183
2,017	153
2,018	126
2,019	124
2,020	114
Thereafter	1,198
Total	1,898
Operating Leases, Rent Expense	3	$ 3	$ 2
Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	78
2,017	76
2,018	49
2,019	49
2,020	41
Thereafter	287
Total	580
Purchased Power
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	28
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	28
Transmission Facilities [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	6
2,017	6
2,018	6
2,019	4
2,020	3
Thereafter	13
Total	38
Renewable Energy Power Purchase Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	61
2,017	61
2,018	61
2,019	61
2,020	60
Thereafter	750
Total	$ 1,054
Percentage of Purchase Power Obligations	100.00%
RES Performance Based Incentives Minimum Commitment [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	$ 8
2,017	8
2,018	8
2,019	8
2,020	8
Thereafter	67
Total	107
Contractual Rights [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	1
2,017	1
2,018	1
2,019	1
2,020	1
Thereafter	77
Total	82
Operating Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	1
2,017	1
2,018	1
2,019	1
2,020	1
Thereafter	4
Total	$ 9
Subsequent Event [Member] | Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016					$ 21
2,017					23
2,018					24
2,019					24
2,020					23
Thereafter					$ 22
Subsequent Event [Member] | Renewable Energy Power Purchase Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016				$ 3
2,017				3
2,018				3
2,019				3
2,020				3
Thereafter				$ 43

COMMITMENTS AND CONTINGENCIES64

COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Detail)	1 Months Ended		12 Months Ended
	Aug. 31, 2015USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2015USD ($)mikV	Feb. 17, 2016USD ($)	Dec. 31, 2014USD ($)
Commitments And Contingencies [Line Items]
Other Receivables, Expenses			$ 39,000,000		$ 17,000,000
Regulatory Assets			264,000,000		292,000,000
Share of Defaulting Participants' Payment on Performance Guarantees			$ 0
Tucson to Nogales [Member]
Commitments And Contingencies [Line Items]
Transmission line from Tucson to Nogales in Milies | mi			60
Transmission Line, in KV | kV			345
Asset Impairment Charges		$ 5,000,000
Regulatory Assets			$ 5,000,000
Navajo [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station			7.50%
Navajo [Member] | Possible Lease Extension [Member]
Commitments And Contingencies [Line Items]
Loss Contingency Accrual, Provision			$ 1,000,000
Estimate of Possible Loss Contingency			$ 3,000,000		2,000,000
Springerville Unit One [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station			49.50%
Springerville Unit One [Member] | Springerville Unit 1 Third Party Owner Allegation [Member] | Pending Litigation [Member]
Commitments And Contingencies [Line Items]
Loss Contingency, Damages Sought, Value			$ 71,000,000
Other Receivables, Expenses			23,000,000
Other Receivables, Capital			$ 4,000,000
Springerville Unit One [Member] | Springerville Unit 1 Third Party Owner Allegation [Member] | Pending Litigation [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Amount paid by Spr Unit 1 Third Party Owners				$ 0
San Juan [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station			50.00%
Percent Ownership Share of Total Generation Capacity			20.00%
San Juan [Member] | Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency			$ 1,000,000
Loss Contingency, Damages Sought, Value			$ 5,000,000
Four Corner [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station			7.00%
Four Corner [Member] | Possible Violation of PSD provisions of the Clean Air [Member] | Settled Litigation [Member]
Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss Capital Exp	$ 2,000,000
Litigation Settlement, Amount O&M	1,000,000
Accrual for Environmental Loss Contingency, Less Than	$ 1,000,000
Four Corner [Member] | Assessment for Coal Severance Tax, Coal Supplier [Member] | Pending Litigation [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency			$ 1,000,000
Loss Contingency, Damages Sought, Value			30,000,000
Navajo, San Juan, Four Corners [Member]
Commitments And Contingencies [Line Items]
Share of Reclamation Costs Anticipated			43,000,000
Environmental Exit Costs, Costs Accrued to Date			$ 25,000,000		$ 22,000,000

EMPLOYEE BENEFIT PLANS (Pension

EMPLOYEE BENEFIT PLANS (Pension and Other Retiree Benefit Related Balance Sheet Amounts) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	$ 264,000,000	$ 292,000,000
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	115,000,000	117,000,000
Accrued Benefit Liability Included in Accrued Employee Expenses	(1,000,000)	(1,000,000)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(57,000,000)	(71,000,000)
Accumulated Other Comprehensive Loss (related to SERP)	5,000,000	5,000,000
Net Total Amount On Balance Sheet	62,000,000	50,000,000
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	5,000,000	9,000,000
Accrued Benefit Liability Included in Accrued Employee Expenses	(2,000,000)	(2,000,000)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(63,000,000)	(67,000,000)
Accumulated Other Comprehensive Loss (related to SERP)	0	0
Net Total Amount On Balance Sheet	$ (60,000,000)	$ (60,000,000)

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$ 407	$ 330
Actuarial (Gain) Loss	(22)	67
Interest Cost	17	16	$ 14
Service Cost	12	10	11
Benefits Paid	(20)	(16)
Projected Benefit Obligation at End of Year	394	407	330
Change in Plan Assets
Fair Value Beginning Balance	335	307
Actual Return on Plan Assets	(3)	35
Benefits Paid	(20)	(16)
Employer Contributions	24	9
Fair Value Ending Balance	336	335	307
Funded Status at End of Year	(58)	(72)
Other Retiree Benefits [Member]
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	81	74
Actuarial (Gain) Loss	(5)	5
Interest Cost	3	3	3
Service Cost	4	4	3
Benefits Paid	(5)	(5)
Projected Benefit Obligation at End of Year	78	81	74
Change in Plan Assets
Fair Value Beginning Balance	12	10
Actual Return on Plan Assets	0	1
Benefits Paid	(5)	(5)
Employer Contributions	6	6
Fair Value Ending Balance	13	12	$ 10
Funded Status at End of Year	$ (65)	$ (69)

EMPLOYEE BENEFIT PLANS (Expecte

EMPLOYEE BENEFIT PLANS (Expected Pension Contributions For Next Year) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	$ 10

EMPLOYEE BENEFIT PLANS (Compone

EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	$ 117	$ 118
Prior Service Cost (Benefit)	3	4
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	6	11
Prior Service Cost (Benefit)	$ (1)	$ (2)

EMPLOYEE BENEFIT PLANS EMPLOYEE

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Detail) $ in Millions	Dec. 31, 2015USD ($)plans	Dec. 31, 2014USD ($)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	2	3
Pension Plan, Defined Benefit [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	$ 188	$ 365
Fair Value of Plan Assets at End of Year	$ 169	$ 335

EMPLOYEE BENEFIT PLANS EMPLOY70

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 12	$ 10	$ 11
Interest Cost	17	16	14
Expected Return on Plan Assets	(23)	(21)	(19)
Actuarial Loss Amortization	7	3	8
Net Periodic Benefit Plan Cost	13	8	14
Other Retiree Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	4	3
Interest Cost	3	3	3
Expected Return on Plan Assets	(1)	(1)	(1)
Actuarial Loss Amortization	0	0	0
Net Periodic Benefit Plan Cost	$ 6	$ 6	$ 5

EMPLOYEE BENEFIT PLANS (Changes

EMPLOYEE BENEFIT PLANS (Changes in Regulatory Assets and Accumulated Comprehensive Income) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan, Defined Benefit [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	$ 5	$ 49	$ (42)
Amortization of Actuarial Gain (Loss)	(7)	(3)	(8)
Total Recognized (Gain) Loss	(2)	46	(50)
Pension Plan, Defined Benefit [Member] | Accumulated Other Comprehensive Loss [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	0	3	(1)
Amortization of Actuarial Gain (Loss)	0	0	0
Total Recognized (Gain) Loss	0	3	(1)
Other Retiree Benefits [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	$ (4)	$ 5	$ (6)

EMPLOYEE BENEFIT PLANS EMPLOY72

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Detail)	Dec. 31, 2015	Dec. 31, 2014
Pension Plan, Defined Benefit [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Rate of Compensation Increase	3.00%	3.00%
Pension Plan, Defined Benefit [Member] | Minimum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	4.50%	4.10%
Pension Plan, Defined Benefit [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	4.60%	4.20%
Other Retiree Benefits [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	4.20%	3.90%

EMPLOYEE BENEFIT PLANS EMPLOY73

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Rate of Compensation Increase	3.00%	3.00%	3.00%
Expected Return on Plan Assets	7.00%	7.00%	7.00%
Pension Plan, Defined Benefit [Member] | Minimum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	4.10%	5.00%	4.10%
Pension Plan, Defined Benefit [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	4.20%	5.10%	4.10%
Other Retiree Benefits [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	3.90%	4.70%	3.80%
Expected Return on Plan Assets	7.00%	7.00%	7.00%

EMPLOYEE BENEFIT PLANS EMPLOY74

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS(Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Health Care Cost Trend Rate Assumed for Next Year	7.60%	6.70%
Ultimate Health Care Cost Trend Rate Assumed	4.50%	4.50%
Year that the Rate Reaches the Ultimate Trend Rate	2,036	2,027

EMPLOYEE BENEFIT PLANS EMPLOY75

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
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	6
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease	$ 5

EMPLOYEE BENEFIT PLANS EMPLOY76

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Detail) - Pension Plan, Defined Benefit [Member]	Dec. 31, 2015	Dec. 31, 2014
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	100.00%	100.00%
Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	49.00%	48.00%
Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	41.00%	43.00%
Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	8.00%	7.00%
Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	2.00%	2.00%

EMPLOYEE BENEFIT PLANS EMPLOY77

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Pension Plan Assets By Level) (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 25,000,000	$ 23,000,000	$ 21,000,000
Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	18,000,000	16,000,000	14,000,000
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
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	13,000,000	12,000,000	10,000,000
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	336,000,000	335,000,000	$ 307,000,000
Pension Plan, Defined Benefit [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, Defined Benefit [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	81,000,000	82,000,000
Pension Plan, Defined Benefit [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	17,000,000	17,000,000
Pension Plan, Defined Benefit [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	67,000,000	61,000,000
Pension Plan, Defined Benefit [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	137,000,000	143,000,000
Pension Plan, Defined Benefit [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	26,000,000	24,000,000
Pension Plan, Defined Benefit [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, Defined Benefit [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, Defined Benefit [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, Defined Benefit [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, Defined Benefit [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, Defined Benefit [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, Defined Benefit [Member] | Level 1 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [Member] | Level 2 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	310,000,000	311,000,000
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	81,000,000	82,000,000
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	17,000,000	17,000,000
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	67,000,000	61,000,000
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	137,000,000	143,000,000
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	8,000,000	8,000,000
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [Member] | Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	25,000,000	23,000,000
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [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, Defined Benefit [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, Defined Benefit [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, Defined Benefit [Member] | Level 3 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	18,000,000	16,000,000
Pension Plan, Defined Benefit [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

EMPLOYEE BENEFIT PLANS EMPLOY78

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Detail) - Level 3 [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	$ 23	$ 21
Actual Return on Plan Assets:
Assets Held at Reporting Date	3	3
Purchases, Sales, and Settlements	(1)	(1)
Fair Value Ending Balance	25	23
Private Equity
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	7	7
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	1
Purchases, Sales, and Settlements	(1)	(1)
Fair Value Ending Balance	7	7
Real Estate
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	16	14
Actual Return on Plan Assets:
Assets Held at Reporting Date	2	2
Purchases, Sales, and Settlements	0	0
Fair Value Ending Balance	$ 18	$ 16

EMPLOYEE BENEFIT PLANS EMPLOY79

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Detail)	12 Months Ended
	Dec. 31, 2015
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
Fixed Income | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	42.00%
Fixed Income | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	38.00%
United States Large Cap | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	24.00%
United States Large Cap | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	39.00%
Non-United States Developed | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	15.00%
Non-United States Developed | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	7.00%
Real Estate | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	8.00%
Real Estate | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
United States Small Cap | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
United States Small Cap | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
Non-United States Emerging | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
Non-United States Emerging | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	9.00%
Private Equity | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	1.00%
Private Equity | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
Cash/Treasury Bills | Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
Cash/Treasury Bills | VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	2.00%

EMPLOYEE BENEFIT PLANS EMPLOY80

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2,016	$ 17
2,017	18
2,018	19
2,019	21
2,020	22
Years 2021-2025	125
Other Retiree Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2,016	5
2,017	5
2,018	5
2,019	6
2,020	6
Years 2021-2025	$ 33

EMPLOYEE BENEFIT PLANS EMPLOY81

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Additional Information) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)plans	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
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
Percentage of net periodic benefit cost that was capitalized	20.00%
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]
Index value percentage of real estate assets	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 25,000,000	23,000,000	21,000,000
Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employer Contributions	24,000,000	9,000,000
Defined Benefit Plan, Accumulated Benefit Obligation	355,000,000	365,000,000
Defined Benefit Plan, Fair Value of Plan Assets	336,000,000	335,000,000	307,000,000
Pension Plan, Defined Benefit [Member] | Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Transfers Between Measurement Levels	0	0
Defined Benefit Plan, Fair Value of Plan Assets	25,000,000	23,000,000
Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employer Contributions	6,000,000	6,000,000
Defined Benefit Plan, Fair Value of Plan Assets	13,000,000	12,000,000	10,000,000
Regulatory Asset [Member] | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Future Amortization of Gain (Loss)	(7,000,000)
Regulatory Asset [Member] | Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Future Amortization of Prior Service Credit (Cost)	1,000,000
Fixed Income | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	137,000,000	143,000,000
Fixed Income | Pension Plan, Defined Benefit [Member] | Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employer Contributions	4,000,000	3,000,000	$ 3,000,000
Defined Benefit Plan, Fair Value of Plan Assets	13,000,000	12,000,000
VEBA Trust [Member] | Other Retiree Benefits [Member] | Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fixed Income | Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5,000,000	4,000,000
VEBA Trust [Member] | VEBA Trust Asset - Equities | Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 8,000,000	$ 8,000,000
Minimum [Member] | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used	25.00%
Maximum [Member] | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used	75.00%

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 3
2015 Share Unit Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent	$ 2
Allocated Share-based Compensation Expense	$ 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	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	23,888

SUPPLEMENTAL CASH FLOW (Cash Pa

SUPPLEMENTAL CASH FLOW (Cash Payments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Interest, Net of Amounts Capitalized	$ 65	$ 83	$ 53
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Construction in Progress Expenditures Incurred but Not yet Paid	$ 28	$ 29	$ 24
Net Cost Of Removal Of Interim Retirements	1	12	25
Commitment to Purchase Capital Lease Interests	0	109	55
Change In Capital Lease Obligations	0	1	9
Escrow Deposits Related to Issuance of Long-Term Debt	0	0	191
Asset Retirement Obligation, Liabilities Incurred	$ 3	$ 4	$ 8

FAIR VALUE MEASUREMENTS AND D85

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Cash Equivalents	$ 33	$ 15
Restricted Cash	4	2
Energy Derivative Contract Assets - Regulatory Recovery	1	2
Energy Derivative Contract Assets - No Regulatory Recovery	1
Total Assets	39	19
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(13)	(18)
Energy Derivative Contract Liabilities - No Regulatory Recovery		(1)
Energy Derivative Contract Liabilities - Cash Flow Hedge		(1)
Interest Rate Swap	(3)	(5)
Total Liabilities	(16)	(25)
Net Total Assets (Liabilities)	23	(6)
Level 1 [Member]
Assets
Cash Equivalents	33	15
Restricted Cash	4	2
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0
Total Assets	37	17
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Energy Derivative Contract Liabilities - No Regulatory Recovery		0
Energy Derivative Contract Liabilities - Cash Flow Hedge		0
Interest Rate Swap	0	0
Total Liabilities	0	0
Net Total Assets (Liabilities)	37	17
Level 2 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	1	0
Energy Derivative Contract Assets - No Regulatory Recovery	0
Total Assets	1	0
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(10)	(9)
Energy Derivative Contract Liabilities - No Regulatory Recovery		0
Energy Derivative Contract Liabilities - Cash Flow Hedge		0
Interest Rate Swap	(3)	(5)
Total Liabilities	(13)	(14)
Net Total Assets (Liabilities)	(12)	(14)
Level 3 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	0	2
Energy Derivative Contract Assets - No Regulatory Recovery	1
Total Assets	1	2
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(3)	(9)
Energy Derivative Contract Liabilities - No Regulatory Recovery		(1)
Energy Derivative Contract Liabilities - Cash Flow Hedge		(1)
Interest Rate Swap	0	0
Total Liabilities	(3)	(11)
Net Total Assets (Liabilities)	$ (2)	$ (9)

FAIR VALUE MEASUREMENTS AND D86

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Energy Related Derivative [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Asset, Fair Value, Gross Amount Recognized on the Balance Sheets	$ 2	$ 2
Derivative Asset, Counterparty Netting	1	2
Collateral Received	0	0
Derivative Asset, Net Amount	1	0
Derivative Liability, Fair Value, Gross Amount Recognized on the Balance Sheets	(13)	(20)
Derivative Liability, Counterparty Netting	(1)	(2)
Collateral Posted	0	0
Derivative Liability, Net Amount	(12)	(18)
Interest Rate Swap [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Liability, Fair Value, Gross Amount Recognized on the Balance Sheets	(3)	(5)
Derivative Liability, Counterparty Netting	0	0
Collateral Posted	0	0
Derivative Liability, Net Amount	$ (3)	$ (5)

FAIR VALUE MEASUREMENTS AND D87

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Derivative [Line Items]
Cash Flow Hedge Loss to be Reclassified within Twelve Months	$ 1
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Liability, Notional Amount	$ 29

FAIR VALUE MEASUREMENTS AND D88

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Capital Lease Interest Expense	$ 3,994	$ 10,249	$ 25,140
Long-Term Debt Interest Expense	61,159	60,577	56,378
Purchased Power	124,764	152,922	112,452
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Capital Lease Interest Expense	2,000	2,000	2,000
Long-Term Debt Interest Expense	0	1,000	1,000
Purchased Power	$ 1,000	$ 1,000	$ 1,000

FAIR VALUE MEASUREMENTS AND D89

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	12 Months Ended			36 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Percent of gains shared with ratepayers	10.00%
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$ 6	$ (18)	$ 0
Scenario, Forecast [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Term of Contract for which Normal Sale Election Made				3 years

FAIR VALUE MEASUREMENTS AND D90

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Millions	Dec. 31, 2015GWhBTU	Dec. 31, 2014GWhBTU
Power Contracts (in GWh) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | GWh	1,752	2,604
Gas Contracts (in GBtu) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | BTU	17,214	19,932

FAIR VALUE MEASUREMENTS AND D91

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) - Level 3 [Member] $ in Millions	Dec. 31, 2015USD ($)$ / MMBTU$ / megawatt_hour	Dec. 31, 2014USD ($)	Dec. 31, 2014	Dec. 31, 2014$ / MMBTU	Dec. 31, 2014$ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$ 1	$ 2
Derivative Liabilities	(3)	(11)
Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	1	1
Derivative Liabilities	(2)	(6)
Market Approach Valuation Technique [Member] | Power Sale Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets		1
Derivative Liabilities		(1)
Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	0	0
Derivative Liabilities	$ (1)	$ (4)
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / megawatt_hour	19.20				22.35
Minimum [Member] | Market Approach Valuation Technique [Member] | Power Sale Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price				2.88	27.75
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			2.72
Gas Volatility	31.00%		30.80%
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / megawatt_hour	31.35				39.05
Maximum [Member] | Market Approach Valuation Technique [Member] | Power Sale Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price				4.02	44.94
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			3.26
Gas Volatility	58.30%		53.30%

FAIR VALUE MEASUREMENTS AND D92

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning balance	$ (9,000,000)	$ (2,000,000)
Gains (Losses) Recorded to:
Gains (Losses) Recorded to Net Regulatory Assets/Liabilities - Derivative Instruments	(4,000,000)	(8,000,000)
Gains/(Losses) Recorded to Electric Wholesale Sales	3,000,000	0
Settlements	8,000,000	1,000,000
Ending balance	(2,000,000)	(9,000,000)
Change in Unrealized Gains (Losses) related to Assets (Liabilities) still held	(1,000,000)	(8,000,000)
Transfers out of Level 3	$ 0	$ 0

FAIR VALUE MEASUREMENTS AND D93

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features	$ 20,000,000	$ 27,000,000
Additional collateral if credit-risk contingent features are triggered	20,000,000
Line of Credit Collateral [Member]
Derivative [Line Items]
Letter of Credit Less Than	1,000,000
Accounts Payable and Accrued Liabilities [Member]
Derivative [Line Items]
Additional collateral if credit-risk contingent features are triggered	$ 8,000,000

FAIR VALUE MEASUREMENTS AND D94

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-term Debt, Gross	$ 1,466	$ 1,375
Level 2 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-term Debt, Fair Value	$ 1,529	$ 1,457

INCOME TAXES (Differences betwe

INCOME TAXES (Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Statutory tax rate	35.00%
Federal Income Tax Expense at Statutory Rate	$ 70,000	$ 56,000	$ 52,000
State Income Tax Expense, Net of Federal Deduction	8,000	7,000	7,000
Federal/State Tax Credits	(8,000)	(5,000)	(2,000)
Allowance for Equity Funds Used During Construction	(1,000)	(2,000)	(1,000)
Deferred Tax Asset Valuation Allowance	1,000	0	2,000
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	0	0	(11,000)
Other	2,000	2,000	1,000
Total Federal and State Income Tax Expense	$ 71,719	$ 57,911	$ 47,986

INCOME TAXES (Income Tax Expens

INCOME TAXES (Income Tax Expense Included in Income Statements) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Tax Expense (Benefit)
Federal	$ 0	$ (1,000)	$ (8,000)
State	0	0	(2,000)
Total	0	(1,000)	(10,000)
Deferred Tax Expense (Benefit)
Federal	66,000	54,000	47,000
Federal Investment Tax Credits	(6,000)	(4,000)	(1,000)
State	12,000	9,000	12,000
Total Deferred Tax Expense (Benefit)	72,000	59,000	58,000
Income Tax Expense	$ 71,719	$ 57,911	$ 47,986

INCOME TAXES (The Significant C

INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Gross Deferred Income Tax Assets
Capital Lease Obligations	$ 27	$ 96
Net Operating Loss Carryforwards	156	187
Customer Advances and Contributions in Aid of Construction	20	19
Alternative Minimum Tax Credit	24	24
Accrued Postretirement Benefits	23	23
Emission Allowance Inventory	9	10
Deferred Tax Assets Unregulated Investment Losses	32	31
Other	53	54
Gross Deferred Income Tax Assets	344	444
Deferred Tax Assets Valuation Allowance	(4)	(2)
Gross Deferred Income Tax Liabilities
Plant - Net	(750)	(699)
Capital Lease Assets - Net	(12)	(74)
Pensions	(27)	(27)
PPFAC	0	(8)
Other	(19)	(24)
Deferred Tax Liabilities, Gross	(808)	(832)
Deferred Tax Liabilities, Net	$ (468)	$ (390)

INCOME TAXES (Summary of Tax Ca

INCOME TAXES (Summary of Tax Carryforwards) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	$ 430
Tax Credits	24
Investment Tax Credits	32
State Tax Jurisdiction [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	114
Tax Credits	$ 10

INCOME TAXES (Additional Inform

INCOME TAXES (Additional Information) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Deferred Tax Asset Valuation Allowance	$ 4,000,000	$ 2,000,000
Unrecognized Tax Benefits Reducing Income Tax Expense	1,000,000	0
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 and Interest Accrued	$ 0	$ 0

INCOME TAXES (Uncertain Tax Pos

INCOME TAXES (Uncertain Tax Positions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 4	$ 2
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	1	2
Unrecognized Tax Benefits	$ 5	$ 4

INCOME TAXES (Operating Loss Ca

INCOME TAXES (Operating Loss Carryforwards, Expiration Date) (Details)	12 Months Ended
	Dec. 31, 2015
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]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2016
Tax Credit Carryforwards, Expiration Date	Dec. 31, 2016
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, 2035
Alternative Minimum Tax Credit Carryforwards, Expiration Date	None
Maximum [Member] | State Tax Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2034
Tax Credit Carryforwards, Expiration Date	Dec. 31, 2030

QUARTERLY FINANCIAL DATA (Summa

QUARTERLY FINANCIAL DATA (Summary of Quarterly Financial Data) (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating Revenue	$ 284,000	$ 409,000	$ 340,000	$ 273,000	$ 305,000	$ 387,000	$ 322,000	$ 256,000	$ 1,306,544	$ 1,269,901	$ 1,196,690
Operating Income	36,000	120,000	74,000	28,000	34,000	85,000	80,000	32,000	$ 259,303	$ 230,688	$ 230,371
Net Income (Loss)	$ 12,000	$ 69,000	$ 38,000	$ 9,000	$ 15,000	$ 40,000	$ 39,000	$ 9,000