Tucson Electric Power 10-K 19 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	100122
Current Fiscal Year End Date	-19
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_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Utility Plant
Plant in Service	$5,175,148	$4,467,667
Utility Plant Under Capital Leases	667,157	637,957
Construction Work in Progress	109,070	180,485
Total Utility Plant	5,951,375	5,286,109
Less Accumulated Depreciation and Amortization	-2,052,216	-1,826,977
Less Accumulated Amortization of Capital Lease Assets	-473,969	-514,677
Total Utility Plant—Net	3,425,190	2,944,455
Investments and Other Property
Investments in Lease Equity	0	36,194
Other	37,599	33,488
Total Investments and Other Property	37,599	69,682
Current Assets
Cash and Cash Equivalents	74,170	25,335
Accounts Receivable—Customer	93,521	80,211
Unbilled Accounts Receivable	36,804	34,369
Allowance for Doubtful Accounts	-4,885	-4,825
Accounts Receivable—Due from Affiliates	5,382	6,064
Materials and Supplies	86,750	75,200
Deferred Income Taxes—Current	102,006	70,722
Fuel Inventory	36,368	44,027
Regulatory Assets—Current	69,383	42,555
Derivative Instruments	1,633	2,137
Other	22,848	12,923
Total Current Assets	523,980	388,718
Regulatory and Other Assets
Regulatory Assets—Noncurrent	223,192	141,030
Derivative Instruments	300	167
Other Assets	22,161	19,233
Total Regulatory and Other Assets	245,653	160,430
Total Assets	4,232,422	3,563,285
Capitalization
Common Stock Equity	1,215,779	925,923
Capital Lease Obligations	69,438	131,370
Long-Term Debt	1,372,414	1,223,070
Total Capitalization	2,657,631	2,280,363
Current Liabilities
Current Obligations Under Capital Leases	173,822	186,056
Borrowings Under Revolving Credit Facilities	85,000	0
Accounts Payable—Trade	110,480	88,556
Accounts Payable—Due to Affiliates	2,933	9,153
Accrued Taxes Other than Income Taxes	36,110	34,485
Accrued Employee Expenses	15,679	24,454
Regulatory Liabilities—Current	38,847	23,701
Accrued Interest	21,021	22,785
Customer Deposits	20,339	21,354
Derivative Instruments	18,874	5,531
Other	9,673	9,244
Total Current Liabilities	532,778	425,319
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	491,546	428,103
Regulatory Liabilities—Noncurrent	321,186	263,270
Pension and Other Postretirement Benefits	138,319	84,936
Derivative Instruments	6,288	5,161
Other	84,674	76,133
Total Deferred Credits and Other Liabilities	1,042,013	857,603
Commitments, Contingencies & Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$4,232,422	$3,563,285

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues
Electric Retail Sales	$970,145	$934,357	$915,879
Electric Wholesale Sales	158,323	132,500	111,194
Other Revenues	141,433	129,833	134,587
Total Operating Revenues	1,269,901	1,196,690	1,161,660
Operating Expenses
Fuel	297,537	325,903	318,901
Purchased Power	152,922	112,452	80,137
Transmission and Other PPFAC Recoverable Costs	18,179	12,233	5,722
Increase (Decrease) to Reflect PPFAC Recovery Treatment	-11,194	-12,458	31,113
Total Fuel and Purchased Energy	457,444	438,130	435,873
Operations and Maintenance	378,877	335,321	334,553
Depreciation	126,520	118,076	110,931
Amortization	28,567	31,294	39,493
Taxes Other Than Income Taxes	47,805	43,498	40,323
Total Operating Expenses	1,039,213	966,319	961,173
Operating Income	230,688	230,371	200,487
Other Income (Deductions)
Interest Income	208	120	136
Other Income	8,598	5,770	3,953
Other Expense	-12,735	-10,715	-13,574
Appreciation in Fair Value of Investments	1,371	2,833	1,892
Total Other Income (Deductions)	-2,558	-1,992	-7,593
Interest Expense
Long-Term Debt	60,577	56,378	55,038
Capital Leases	10,249	25,140	33,613
Other Interest Expense	810	87	1,446
Interest Capitalized	-3,755	-2,554	-1,782
Total Interest Expense	67,881	79,051	88,315
Income Before Income Taxes	160,249	149,328	104,579
Income Tax Expense	57,911	47,986	39,109
Net Income	$102,338	$101,342	$65,470

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income	$102,338	$101,342	$65,470
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:	1,675	2,738	1,354
Supplemental Executive Retirement Plan (SERP) Benefit Amortization:	-1,725	916	-840
Total Other Comprehensive Income (Loss), Net of Taxes	-50	3,654	514
Total Comprehensive Income	$102,288	$104,996	$65,984

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Income Tax Expense in Fair Value of Cash Flow Hedges	($1,140)	($1,793)	($887)
Income Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	$1,068	($572)	$608

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Cash Flows [Abstract]
Net Income	$102,338	$101,342	$65,470
Cash Flows from Operating Activities
Depreciation	126,520	118,076	110,931
Amortization Expense	28,567	31,294	39,493
Amortization of Deferred Debt-Related Costs included in Interest Expense	2,626	2,452	2,227
Use of Renewable Energy Credits for Compliance	17,818	15,990	5,071
Deferred Income Taxes	62,609	59,199	45,232
Pension and Retiree Expense	13,648	19,878	19,289
Pension and Retiree Funding	-14,388	-27,636	-25,899
Share-Based Compensation Expense	5,010	2,709	2,029
Allowance for Equity Funds Used During Construction	-6,677	-4,526	-2,840
LFCR Revenue	-11,327	-2,171	0
Increase (Decrease) to Reflect PPFAC Recovery Treatment	-11,194	-12,458	31,113
Fortis Acquisition Direct Customer Benefit	18,870	0	0
PPFAC Reduction - 2013 TEP Rate Order	0	3,000	0
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately[Abstract]
Accounts Receivable	-14,599	-6,041	-871
Materials and Fuel Inventory	666	16,145	-38,384
Accounts Payable	10,712	334	1,115
Interest Accrued	-377	4,859	8,055
Taxes Other Than Income Taxes	1,625	1,425	905
Current Regulatory Liabilities	8,388	3,331	-3,040
Other	-27,172	18,989	8,023
Net Cash Flows – Operating Activities	313,663	346,191	267,919
Cash Flows from Investing Activities
Capital Expenditures	-323,524	-252,848	-252,782
Purchase of Gila River Unit 3	-163,938	0	0
Purchase of Springerville Unit 1 Lease Assets	-19,608	0	0
Purchase of Intangibles—Renewable Energy Credits	-28,334	-23,280	-8,889
Return of Investments in Springerville Lease Debt	0	9,104	19,278
Contributions in Aid of Construction	15,903	3,959	9,982
Other, net	1,863	3,403	4,530
Net Cash Flows—Investing Activities	-517,638	-259,662	-227,881
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	275,000	78,000	189,000
Repayments of Borrowings Under Revolving Credit Facilities	-190,000	-78,000	-199,000
Proceeds from Issuance of Long-Term Debt	149,168	0	149,513
Payments of Capital Lease Obligations	-165,145	-99,621	-89,452
Dividends Paid to UNS Energy	-40,000	-40,000	-30,000
Repayments of Long-Term Debt	0	0	-6,535
Payment of Debt Issue/Retirement Costs	-1,856	-1,865	-3,547
Equity Investment from UNS Energy	225,000	0	0
Other, net	643	549	2,008
Net Cash Flows—Financing Activities	252,810	-140,937	11,987
Net Increase (Decrease) in Cash and Cash Equivalents	48,835	-54,408	52,025
Cash and Cash Equivalents, Beginning of Year	25,335	79,743	27,718
Cash and Cash Equivalents, End of Year	$74,170	$25,335	$79,743

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	Common Stock Including Additional Paid in Capital [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
In Thousands, unless otherwise specified
Balances at December 31 at Dec. 31, 2011	$824,943	$888,971	($6,357)	($47,627)	($10,044)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	65,470			65,470
Other Comprehensive Loss, net of tax	514				514
Payments of Ordinary Dividends, Common Stock	30,000
Dividends Declared	-30,000			-30,000
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
Payments of Ordinary Dividends, Common Stock	40,000
Dividends Declared	-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
Payments of Ordinary Dividends, Common Stock	40,000
Dividends Declared	-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)

CONSOLIDATED_STATEMENTS_OF_CAP

CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	32,139,434	32,139,434
Common Stock Equity	$1,215,779	$925,923
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
No Par Value, 1,000,000 Shares Authorized, None Outstanding	0	0
Capital Lease Obligations [Abstract]
Capital Lease Obligations	243,260	317,426
Less Current Maturities	-173,822	-186,056
Total Long-Term Capital Lease Obligations	69,438	131,370
Long-term Debt, Unclassified [Abstract]
Long-term Debt	1,372,414	1,223,070
Total Capitalization	2,657,631	2,280,363
Springerville Unit 1
Capital Lease Obligations [Abstract]
Capital Lease Obligations	42,925	192,871
Springerville Coal Handling Facilities
Capital Lease Obligations [Abstract]
Capital Lease Obligations	117,573	27,878
Springerville Common Facilities
Capital Lease Obligations [Abstract]
Capital Lease Obligations	82,762	96,677
Variable Rate Bonds
Long-term Debt, Unclassified [Abstract]
Long-term Debt	214,830	214,802
Debt Instrument, Maturity Date Range, Start	1-Oct-22
Debt Instrument, Maturity Date Range, End	1-Apr-32
Debt Instrument Interest Rate	Variable
Fixed Rate Bonds
Long-term Debt, Unclassified [Abstract]
Long-term Debt	1,157,584	1,008,268
Debt Instrument, Maturity Date Range, Start	1-Oct-20
Debt Instrument, Maturity Date Range, End	15-Mar-44
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	3.85%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	5.75%
Common Stock-No Par Value
Common Stock Equity	1,116,539	888,971
Capital Stock Expense
Common Stock Equity	-6,357	-6,357
Accumulated Earnings
Common Stock Equity	111,523	49,185
Accumulated Other Comprehensive Income (Loss) [Member]
Common Stock Equity	($5,926)	($5,876)

NATURE_OF_OPERATIONS_AND_SUMMA

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2014
Text Block [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 415,000 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), which is a leader in the North American electric and gas utility business.
	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. 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 Merger being completed, TEP recorded approximately $15 million through August 2014 as its allocated share of merger-related expenses, in addition to the customer bill credits discussed above. Merger-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.
	Completion of the Merger resulted in accelerated vesting and expense recognition of all outstanding non-vested UNS Energy share-based awards that 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, $3 million for the year ended December 31, 2013, and $2 million for the year ended December 31, 2012. In August 2014, UNS Energy settled all outstanding share-based compensation awards in cash.
	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 of Notes to Consolidated Financial Statements. 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 in the consolidated statements of income. See Note 3 of Notes to Consolidated Financial Statements.
	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 Merger were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis.
	As a result of the Merger, TEP has elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current period presentation.
	REVISION OF BALANCE SHEET AND STATEMENT OF CAPITALIZATION AS OF DECEMBER 31, 2013
	TEP revised its December 31, 2013 balance sheet and statement of capitalization to correct an immaterial error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. The notes that follow have been updated for this revision.
	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2014, we adopted accounting guidance that:
	•	requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.
	•	impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.
	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 items 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 of Notes to Consolidated Financial Statements.
	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—Other on the balance sheets. Restricted cash was $2 million at December 31, 2014 and December 31, 2013.
	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. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. 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:
		2014		2013		2012
	Average AFUDC Rates	7.3	%	7.38	%	7.22	%
	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 2 and Note 3 of Notes to Consolidated Financial Statements. 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:
		2014		2013		2012
	Average Annual Depreciation Rates	2.99	%	3.16	%	3.22	%
	Utility Plant Under Capital Leases
	TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 3 of Notes to Consolidated Financial Statements) and Interest Expense—Capital Leases. The lease terms are described in Note 5 of Notes to Consolidated Financial Statements.
	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.
	INVESTMENTS IN LEASE EQUITY
	Prior to December 2014, TEP held a 14.1% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 10 of Notes to Consolidated Financial Statements.
	TEP accounted for its equity interest in the Springerville Unit 1 Lease trust using the equity method. In December 2014, following the purchase of an additional undivided interest in Springerville Unit 1, TEP transferred the balance of its investment in lease equity to Plant in Service.
	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. 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. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.
	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. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
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 electricity 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 kWh sales lost due to Energy Efficiency (EE) Standards and Distributed Generation (DG). 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.
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.
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.
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 of Notes to Consolidated Financial Statements.
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 Electric EE Standards require increasing annual targeted retail Kilowatt-hours (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 of Notes to Consolidated Financial Statements.
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 – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due to TEP from ratepayers as these tax benefits reverse. See Note 2 of Notes to Consolidated Financial Statements.
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 effective July 1, 2013 due to the 2013 TEP Rate Order. 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.
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.
Cash Flow Hedges
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. TEP accounts for cash flow hedges as follows:
•	The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and
•	When TEP determines a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.
We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.
Energy Contracts - Regulatory Recovery
TEP is authorized to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC mechanism.
Energy Contracts - No Regulatory Recovery
From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery.
Master Netting Agreements
We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.
Normal Purchases and Normal Sales
We enter into forward energy purchase and sales contracts, including options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.
Commodity Trading
We did not engage in trading of derivative financial instruments for the periods presented.
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 sheets. 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 of Notes to Consolidated Financial Statements.

REGULATORY_MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS
	The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
	2013 TEP RATE ORDER
	The provisions of the 2013 TEP Rate Order, which were effective July 1, 2013, include, but are not limited to:
	•	An annual increase in Base Rates of approximately $76 million.
	•	A revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant regulated by the ACC, primarily due to revised estimates of asset removal costs, which has the effect of reducing depreciation expense by approximately $11 million annually.
	•	A LFCR mechanism that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to EE programs and DG. The LFCR rate adjusts annually and is subject to ACC review and a year-over-year cap of 1% of TEP's total retail revenues.
	•	An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA adjusts annually to recover environmental compliance costs and is subject to ACC approval and a cap of 0.025 cents per kWh, which approximates 0.25% of TEP's total retail revenues.
	COST RECOVERY MECHANISMS
	Purchased Power and Fuel Adjustment Clause
	The PPFAC rate is adjusted annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: 1) a forward component, under which TEP recovers or refunds differences between a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.
	In April 2014, the ACC approved a PPFAC rate for TEP of 0.10 cents per kWh for the period May through September 2014 and 0.50 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was 0.77 cents per kWh for the period of January 2013 through June 2013 and a credit of approximately 0.14 cents per kWh for the period July 2013 through April 2014.
	San Juan Mine Fire Insurance Proceeds
	In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP 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 and distribution of insurance proceeds to San Juan participants. As of December 31, 2014, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.
	Environmental Compliance Adjustor
	The 2013 TEP Rate Order provided for the ECA to recover costs associated with qualified investments to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP recognized ECA revenues of less than $1 million in 2014.
	Renewable Energy Standards
	TEP is required to expand its use of renewable energy in order to meet the ACC’s Renewable Energy Standards (RES). TEP is authorized to recover costs associated with meeting the RES through a customer surcharge. These costs include purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates.
	In December 2014, the ACC approved TEP's 2015 RES plan that included a spending budget of $40 million with $33 million to be recovered through the RES surcharge. TEP earned returns on solar investments of less than $1 million in 2014 and $2 million in 2013.
	Energy Efficiency Standards
	TEP is required to implement cost-effective DSM programs to comply with the ACC's EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as a performance incentive. For the year ended December 31, 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Revenue in the TEP income statement.
	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 EE programs and DG targets. For recovery of lost fixed costs, TEP is required to file an annual LFCR adjustment request with the ACC for costs related to the prior year, and recovery is subject to a year-over-year cap of 1% of the company's total retail revenues.
	The ACC approved TEP's annual LFCR recovery request for lost fixed costs incurred in 2013 of approximately $5 million. The approved rates, of approximately 0.41% of retail revenue for EE and approximately 0.31% of retail revenue for DG, became effective August 2014.
	TEP recorded, in Electric Retail Sales, LFCR revenues of $11 million for the year ended December 31, 2014 related to reductions in retail kWh sales for 2013 and 2014. We recognize LFCR revenue when verifiable regardless of when the lost retail kWh sales occur.
	The following table summarizes regulatory assets and liabilities:
		December 31, 2014			December 31, 2013
		Millions of Dollars
	Regulatory Assets—Current
	Property Tax Deferrals (1)	$	21		$	20
	PPFAC (2)	19			4
	Derivative Instruments (Note 10)	15			1
	LFCR and DSM (2)	8			3
	San Juan Mine Fire Cost Deferral (2)	2			10
	Other Current Regulatory Assets (3)	4			5
	Total Regulatory Assets—Current	69			43
	Regulatory Assets—Noncurrent
	Pension and Other Retiree Benefits (Note 8)	126			75
	Income Taxes Recoverable Through Future Rates (4)	31			22
	PPFAC - Final Mine Reclamation and Retiree Health Care Costs (5)	29			25
	Springerville Lease Purchase Commitment Deferrals (6)	16			2
	Unamortized Loss on Reacquired Debt (7)	6			7
	LFCR (2)	4			—
	Tucson to Nogales Transmission Line (8)	4			5
	Other Regulatory Assets (3)	7			5
	Total Regulatory Assets—Noncurrent	223			141
	Regulatory Liabilities—Current
	RES (2)	(28		)	(22		)
	DSM (2)	(6		)	—
	Fortis Merger Customer Credits (9)	(5		)	—
	Other Current Regulatory Liabilities	—			(2		)
	Total Regulatory Liabilities—Current	(39		)	(24		)
	Regulatory Liabilities—Noncurrent
	Net Cost of Removal for Interim Retirements (10)	(265		)	(254		)
	Deferred Investment Tax Credits (11)	(25		)	(4		)
	Income Taxes Payable through Future Rates (4)	(20		)	(5		)
	Fortis Merger Customer Credits (9)	(11		)	—
	Total Regulatory Liabilities—Noncurrent	(321		)	(263		)
	Total Net Regulatory Assets (Liabilities)	$	(68	)	$	(103	)
	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, 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.
	(1)	Property Taxes are recovered over approximately a six months period as costs are paid, rather than as costs are accrued.
	(2)	See Cost Recovery Mechanisms discussed above.
	(3)	Other regulatory assets include self-insured medical costs and short-term disability costs recovered on a pay-as-you-go or cash basis; San Juan Coal Contract Amendment costs (recovery through 2017); rate case costs (recovery over three years); and environmental compliance costs (recovery over one year).
	(4)	Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. See Note 1 of Notes to Consolidated Financial Statements.
(5)	Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
(6)	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 5 of Notes to Consolidated Financial Statements.
(7)	In accordance with FERC guidelines, when TEP refinances its long-term debt, TEP defers and amortizes losses on reacquired debt over the life of the debt agreement.
(8)	TEP will request recovery from FERC for the costs incurred to develop a high-voltage transmission line from Tucson to Nogales; the project is not going forward. See Note 6 of Notes to Consolidated Financial Statements
(9)	Fortis Merger Customer Credits represent credits to be applied to customers’ bills according to the Merger Agreement. These credits will be applied to customer bills each year, October through March for a period of five years. See Note 1 of Notes to Consolidated Financial Statements.
(10)	Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.
(11)	The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is 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_JOINTLYOWNED

UTILITY PLANT AND JOINTLY-OWNED FACILITIES	12 Months Ended
	Dec. 31, 2014
Regulatory 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,
		2014				2013
		Millions of Dollars
	Plant in Service:
	Electric Generation Plant	$	2,388			$	1,889
	Electric Transmission Plant	898				825
	Electric Distribution Plant	1,398				1,298
	General Plant	338				312
	Intangible Plant - Software Costs (1) (2)	149				141
	Electric Plant Held for Future Use	4				3
	Total Plant in Service	$	5,175			$	4,468
	Utility Plant under Capital Leases(3)	$	667			$	638
	(1)	Unamortized computer software costs were $31 million as of December 31, 2014, and $39 million as of December 31, 2013.
	(2)	The amortization of computer software costs was $17 million in 2014, $14 million in 2013, and $13 million in 2012.
	(3)	In 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5 of Notes to Consolidated Financial Statements.
	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 5 of Notes to Consolidated Financial Statements. At December 31, 2014, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for generation-related capital leases:
		Year Ended December 31,
		2014				2013				2012
		Millions of Dollars
	Lease Expense:
	Interest Expense – Included in:
	Capital Leases	$	10			$	25			$	34
	Operating Expenses – Fuel	1				2				3
	Amortization of Capital Lease Assets – Included in:
	Operating Expenses – Fuel	6				5				4
	Operating Expenses – Amortization	16				15				14
	Total Lease Expense	$	33			$	47			$	55
	Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2014, were as follows:
		31-Dec-14
		Annual Depreciation Rate (3)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Electric Generation Plant (1)	3.31%		22
	Electric Transmission Plant	1.48%		32
	Electric Distribution Plant (1)	2.08%		35
	General Plant (1)	5.48%		11
	Intangible Plant (2)	Various		Various
	(1)	In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 2 of Notes to Consolidated Financial Statements.
	(2)	The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life of three to five years for smaller application software. For large enterprise software, we use the remaining life depreciation method. At December 31, 2014, remaining lives ranged from one to six years.
	(3)	The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.
	JOINTLY-OWNED FACILITIES
	At December 31, 2014, TEP was a participant in jointly-owned generating stations and transmission systems as follows:
		Ownership Percentage		Plant in Service				Construction Work in				Accumulated Depreciation		Net Book Value
								Progress
				Millions of Dollars
	San Juan Units 1 and 2	50.00%		$	453			$	8			$	242	$	219
	Navajo Units 1, 2, and 3	7.50%		153				1				112		42
	Four Corners Units 4 and 5	7.00%		104				3				77		30
	Luna Energy Facility	33.30%		55				—				2		53
	Gila River Unit 3	75.00%		186				—				54		132
	Gila River Common Facilities	18.75%		42				—				11		31
	Transmission Facilities	Various		371				21				193		199
	Total			$	1,364			$	33			$	691	$	706
	In December 2014, TEP completed the purchase of Gila River Unit 3. TEP jointly owns Gila River Unit 3 with UNS Electric, Inc., an affiliated subsidiary of UNS Energy (UNS Electric). See Note 7 of Notes to Consolidated Financial Statements.
	TEP is responsible for its share of operating and capital costs for the above facilities. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
	Springerville Unit 1
	At December 31, 2014, TEP owned 24.7% of Springerville Unit 1 and continued to lease the remaining portion of the facility. Effective January 1, 2015, following completion of the purchase of an additional 24.8% leased interest in Springerville Unit 1 and expiration of the lease, TEP has a 49.5% ownership interest in the Springerville Unit 1 generating station and will operate the facility on behalf of third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). The Third-Party Owners are responsible for their share of operating and capital costs for the facility. See Note 6 of Notes to Consolidated Financial Statements.
	ASSET RETIREMENT OBLIGATIONS
	The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:
		December 31,
		2014				2013
	Millions of Dollars
Beginning Balance	$	22			$	14
Liabilities Incurred	5				—
Accretion Expense or Regulatory Deferral	1				1
Revisions to the Present Value of Estimated Cash Flows (1)	—				7
Ending Balance	$	28			$	22
(1)	Primarily related to changes in expected retirement dates of generating facilities.

RELATED_PARTY_TRANSACTIONS_REL

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS
	TEP engages in various transactions with UNS Energy and its affiliated subsidiaries including Unisource Energy Services, Inc., UNS Electric, UNS Gas, Inc. (UNS Gas) and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy affiliates). These transactions include sales and purchases of power, common cost allocations, and the provision of corporate and other labor related services. Additionally, TEP and UNS Electric jointly own a generating station unit. See Note 7 of Notes to Consolidated Financial Statements.
	The following table summarizes related party transactions:
		Years Ended December 31,
		2014		2013		2012
		Millions of Dollars
	Wholesale Sales - TEP to UNS Electric (1)	$	4	$	1	$	2
	Wholesale Sales - UNS Electric to TEP (1)	4		2		1
	Control Area Services - TEP to UNS Electric (2)	3		4		3
	Common Costs - TEP to UNS Energy Affiliates (3)	13		12		12
	Supplemental Workforce - UNS Energy Affiliate to TEP (4)	16		16		17
	Corporate Services - UNS Energy to TEP (5)	14		5		2
	Corporate Services - UNS Energy Affiliates to TEP (6)	1		1		1
	(1)	TEP and UNS Electric sell power to each other at prevailing market prices.
	(2)	TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement.
	(3)	Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
	(4)	SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable.
	(5)	Corporate costs at UNS Energy, such as merger costs and legal and audit fees, 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.
	(6)	All Corporate Services (e.g., finance, accounting, tax, legal, and information technology) and other labor services are directly assigned to the benefiting entity at a fully burdened cost when possible.
	At December 31, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances:
		31-Dec-14		31-Dec-13
		Millions of Dollars
	Receivables from Related Parties
	UNS Electric	$	4	$	3
	UNS Gas	1		2
	UNS Energy	—		1
	Total Due from Related Parties	$	5	$	6
	Payables to Related Parties
	SES	$	2	$	2
	UNS Electric	1		—
	UNS Energy	—		7
	Total Due to Related Parties	$	3	$	9

DEBT_CREDIT_FACILITIES_AND_CAP

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS
	Long-term debt matures more than one year from the date of the financial statements. We summarize TEP’s long-term debt in the statements of capitalization.
	DEBT ISSUANCES AND REDEMPTIONS
	Fixed Rate Notes
	In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. 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. TEP used the net proceeds to repay approximately $90 million on the outstanding borrowings under the 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.
	In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 2022, with a make-whole premium plus accrued interest. After December 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes.
	Tax-Exempt Fixed Rate Bonds
	In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 2023. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013.
	Tax-Exempt Variable Rate Bonds and Interest Rate Swap
	In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP, due April 2032. The lender resets the interest rate monthly based on a percentage of an index rate equal to one-month LIBOR plus a bank margin rate. In 2014, the average monthly variable rate was 0.87% and ranged from 0.85% to 0.95%. In 2013, the average monthly variable rate was 0.95%. These bonds are multi-modal bonds, and the initial term is set at five years through November 2018, at which time the bonds will be subject to mandatory tender for purchase. Proceeds were deposited with a trustee to redeem $100 million variable rate bonds in December 2013.
	Certain of TEP's tax-exempt, variable rate bonds are supported by Letter of Credits (LOCs) issued under the 2010 Credit Agreement and TEP Reimbursement Agreement, see below.
	The following table shows interest rates (exclusive of LOC and remarketing fees) on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents:
		Years Ended December 31,
		2014		2013		2012
	Interest Rates on Bonds:
	Average Interest Rate	0.08%		0.10%		0.17%
	Range of Average Weekly Rates	.05% - 0.13%		0.06% - 0.25%		0.06% - 0.26%
	In September 2014, an interest rate swap TEP 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 2.4% from September 2009 to September 2014.
	TEP MORTGAGE INDENTURE
	Prior to November 2013, the 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of a credit rating upgrade, in October 2013, TEP canceled $423 million in mortgage bonds and discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.
	CREDIT AGREEMENTS
	2014 Credit Agreement
	In December 2014, TEP entered into an unsecured credit agreement (2014 Credit Agreement). The 2014 Credit Agreement provides for a $130 million term loan commitment and a $70 million revolving credit commitment. Any amounts borrowed under the revolving credit commitment can be used for general corporate purposes. Amounts borrowed under the term loan can only be used to purchase certain tax-exempt bonds in lieu of redemption. All loans made pursuant to the term loan commitment and the revolving credit commitment will be due and payable in November 2015, the termination date of the 2014 Credit Agreement.
	In January 2015, amounts borrowed under the term loan commitment were used to purchase $130 million aggregate principal amount of unsecured IDRBs issued in June 2008 for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.750% and mature in September 2029. At December 31, 2014, the bonds are classified as Long-Term Debt on TEP's balance sheet.
	Loans under the 2014 Credit Agreement bear interest at a variable interest rate consisting of a spread over LIBOR or Alternate Base Rate. Alternate Base Rate is equal to the greater of (i) issuing bank's reference rate, (ii) the federal funds rate plus 1/2 of 1% or (iii) adjusted LIBOR for an interest period of one month plus 0.750%. The interest rate in effect on borrowings is LIBOR plus 0.750% for Eurodollar loans or Alternate Base Rate for Alternate Base Rate loans.
	At December 31, 2014, TEP had a $70 million loan balance under the revolving credit facility and no borrowings under the term loan portion of the 2014 Credit Agreement. The revolving loan balance was included in Current Liabilities on TEP’s balance sheets. At December 31, 2014, there was nothing available under the revolving credit facility and $130 million available under the term loan for the 2014 Credit Agreement. As of 01/30/15, TEP had a $130 million term loan balance outstanding under the 2014 Credit Agreement and a $70 million revolving loan balance.
	2010 Credit Agreement
	TEP’s core credit facility, which was entered into in 2010 and amended in 2011 (2010 Credit Agreement), has an expiration date of November 2016, and will continue to provide TEP with access to $200 million of revolving credit and $82 million in LOCs supporting variable-rate tax-exempt bonds.
	Interest rates and fees under the 2010 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 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million LOC facility is 1.125%.
	At December 31, 2014, TEP had $15 million in borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2013, TEP had no borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2014, there was $185 million available under the revolving credit facility for the 2010 Credit Agreement. The revolving loan balance was included in Current Liabilities on TEP’s balance sheets. The outstanding LOCs are not shown as liabilities on TEP’s balance sheets. As of 01/30/15, TEP had $170 million available under the 2010 Credit Agreement revolving credit facility.
	2010 TEP REIMBURSEMENT AGREEMENT
	A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010. In February 2014, TEP amended the agreement to extend the LOC expiration date from 2014 to 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 1.00% per annum.
	COVENANT COMPLIANCE
	The 2014 Credit Agreement, 2010 Credit Agreement, 2010 TEP Reimbursement Agreement, 2013 Covenants Agreement, and certain of our 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, 2014, we were in compliance with the terms of our long-term debt, 2014 Credit Agreement, 2010 Credit Agreement, 2013 Covenants Agreement, and the 2010 TEP Reimbursement Agreement.
	CAPITAL LEASE OBLIGATIONS
	In January 2015, TEP reduced its capital lease obligations through the scheduled purchase payment for Springerville Unit 1 of $43 million and scheduled payments on other leases of $9 million.
	Springerville Unit 1 Capital Lease Purchases
	The Springerville Unit 1 Leases had an initial term to January 2015, and included a fair market value purchase option at the end of the initial lease term.
	In December 2014, TEP purchased a 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million, the appraised value. Upon purchase, TEP reduced Capital Lease Obligations on its balance sheet for the purchase price. In January 2015, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value.
	With the completion of these lease option purchases, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $1.5 million per month and their share of capital expenditures, which are approximately $7 million in 2015. See Note 6 of Notes to Consolidated Financial Statements.
	Springerville Coal Handling Facilities Lease Purchase Commitment
	In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, in April 2014, TEP recorded an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment.
	Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at December 31, 2014.
	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. Instead of extending the leases, TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of the common facilities are $38 million in 2017 and $68 million in 2021.
	TEP agreed with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Facilities Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either: buy a portion of these facilities; or continue making payments to TEP for the use of these facilities.
	Lease Debt and Equity
	Investments in Springerville Lease Debt and Equity
	In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2013. At December 31, 2014, $36 million was transferred from Lease Equity Investment to Plant in Service on TEP's balance sheet.
	Interest Rate Swap—Springerville Common Facilities Lease Debt
	TEP’s interest rate swap hedges the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month LIBOR plus a credit spread. The applicable spread was 1.75% at December 31, 2014 and December 31, 2013.
	The swap has the effect of fixing the interest rates on the amortizing principal balances as follows:
	Lease Debt Outstanding at December 31, 2014	Fixed			LIBOR
		Rate			Spread
	Notional Amount $32 million - Effective Date June 2006	5.77	%		1.75	%
	TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Note 10 of Notes to Consolidated Financial Statements.
	DEBT MATURITIES
	Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
		Long-Term				Capital			Total
		Debt				Lease
		Maturities (1)				Obligations
		Millions of Dollars
	2015	$	—			$	188		$	188
2016	79				16			95
2017	—				18			18
2018	100				11			111
2019	37				12			49
Total 2015 - 2019	216				245			461
Thereafter	1,159				18			1,177
Less: Imputed Interest	—				(20		)	(20		)
Total	$	1,375			$	243		$	1,618
(1)	$115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to the 2010 Credit Agreement, which expires in November 2016, and the TEP 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the 2010 Credit Agreement and 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. The repayment of TEP Unsecured Notes is not reduced by the remaining $2 million original issue discount.

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
	COMMITMENTS
	At December 31, 2014, TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases.
		2015		2016		2017		2018		2019		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	76	$	78	$	76	$	49	$	49	$	285	$	613
	Purchased Power	22		7		—		—		—		—		29
	Transmission	6		6		6		6		4		16		44
	Renewable Power Purchase Agreements	45		45		45		45		44		565		789
	RES Performance-Based Incentives	8		8		8		8		8		76		116
	Operating Leases:
	Land Easements and Rights-of-Way	2		1		1		1		2		77		84
	Operating Leases Other	1		1		1		1		1		5		10
	Total Purchase Commitments	$	160	$	146	$	137	$	110	$	108	$	1,024	$	1,685
	Fuel
	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.
	TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2017 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. These contracts expire through 2017. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2014.
	TEP has agreements with other utilities to provide transmission services. These contracts expire in various years between 2018 and 2028.
	TEP's purchased power and transmission costs are recoverable from customers through the PPFAC mechanisms.
	Renewable Power Purchase Agreements and RES Performance-Based Incentives
	TEP has entered into 20 year Renewable PPAs which require TEP to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. These agreements have various expiration dates through 2034. TEP has entered into additional long-term renewable PPAs to comply with RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 of Notes to Consolidated Financial Statements.
	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 of Notes to Consolidated Financial Statements.
	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 2014, and $2 million in each of 2013 and 2012.
	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 that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations 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. TEP owns 7.5% of Navajo and, in December 2014, recorded additional lease expense of approximately $2 million related to the lease extension in Deferred Credits and Other Liabilities—Other on TEP's balance sheet.
	Claims Related to Springerville Generating Station Unit 1
	On November 7, 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 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 on January 1 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint.
	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), alleging, among other things, that TEP has refused to comply with the Third-Party Owners' instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses.
	On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice.
	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 injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.
	Claims Related to San Juan Generating Station
	San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (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 estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
	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 cannot predict the final outcome of the BLM’s proposed regulations.
	In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United States 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. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. 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 United States 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 seek 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. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until March 31, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation.
	TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP's estimated share of the settlement offer submitted by APS in August 2014 is less than $1 million. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of costs at this time.
	In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. 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. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. The New Mexico Taxation and Revenue Department and APS continue with settlement negotiations. TEP cannot predict the outcome or timing of resolution of this claim.
	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 $49 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $22 million at December 31, 2014 and $18 million at December 31, 2013.
	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 credit-adjusted risk-free interest rate to be used to discount future liabilities. 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-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 a greater part of 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 believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case.
	Performance Guarantees
	The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, 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 participants. As of December 31, 2014, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements expire in 2016 through 2046.
	ENVIRONMENTAL MATTERS
	Environmental Regulation
	The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $11 million in 2014, $5 million in 2013, and $2 million in 2012 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $28 million in 2015 and $19 million in 2016. In addition, TEP recorded O&M expenses of $5 million in 2014, $8 million in 2013, and $15 million in 2012. TEP expects environmental O&M expenses to be $4 million in each of 2015 and 2016.
	TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
	Hazardous Air Pollutant Requirements
	In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics Standards (MATS) rules, additional emission control equipment will be required by April 2015. TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules. TEP's share of the estimated costs to comply with the MATS rules includes the following:
	Estimated Mercury Emissions Control Costs:	Navajo		Springerville(1)
		Millions of Dollars
	Capital Expenditures	$	1	$	5
	Annual O&M Expenses	1		1
	(1)	Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
	TEP expects Four Corners, Sundt, and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules. Therefore, TEP expects no additional capital expenditures or O&M expenses will be incurred to comply. Although expected to be compliant, Sundt would be required to install additional monitoring equipment, at an estimated cost of less than $1 million, to continue to burn coal after the MATS rules become effective.
	Regional Haze Rules
	The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.
TEP's estimated costs involved in meeting these rules are:
Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital Expenditures	$	28	$	37	$	35	$	12
Annual O&M Expenses	1		1		2		6-May
(1)	In August 2014, the EPA published a final FIP wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
(2)	In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
(3)	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
(4)	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. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

PURCHASE_OF_GASFIRED_GENERATIO

PURCHASE OF GAS-FIRED GENERATION FACILITY	12 Months Ended
	Dec. 31, 2014
Other Commitments [Abstract]
PURCHASE OF GAS-FIRED GENERATION FACILITY	NOTE 7. PURCHASE OF GAS-FIRED GENERATION FACILITY
	On December 10, 2014, TEP and UNS Electric acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 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. Upon the closing of the transaction, the letter of credit TEP provided in June 2014 for $15 million was canceled.
	TEP’s purchase of Gila River Unit 3 is 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 has been 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:
		Millions of Dollars
	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 Deferred Credits and Other Liabilities - Other on TEP's balance sheet.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS
	PENSION BENEFIT PLANS
	We sponsor two noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We fund the pension plans by contributing at least the minimum amount required under 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 $3 million in each of 2014, 2013 and 2012 to the VEBA. Other retiree benefits for unclassified employees are self-funded.
	TEP’s other retiree benefit plan was amended in 2012 to increase the participant contributions for classified employees who retire after February 1, 2014. The effect on the benefit obligation was less than $1 million.
	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 pension and other retiree benefit related amounts (excluding tax balances) included on our balance sheet are:
		Pension Benefits							Other Retiree
									Benefits
		Years Ended December 31,
		2014				2013			2014			2013
		Millions of Dollars
	Regulatory Pension Asset Included in Other Regulatory Assets	$	117			$	71		$	9		$	4
	Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)		(1		)	(2		)	(2		)
	Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(71		)		(23		)	(67		)	(62		)
	Accumulated Other Comprehensive Loss (related to SERP)	5				2			—			—
	Net Amount Recognized	$	50			$	49		$	(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, 2014 and December 31, 2013. The table below includes all of TEP’s plans. All plans have projected benefit obligations in excess of 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
		Years Ended December 31,
		2014				2013			2014			2013
		Millions of Dollars
	Change in Projected Benefit Obligation
	Benefit Obligation at Beginning of Year	$	330			$	357		$	74		$	77
	Actuarial (Gain) Loss	67				(35		)	5			(5		)
	Interest Cost	16				14			3			3
	Service Cost	10				11			4			3
	Benefits Paid	(16		)		(17		)	(5		)	(4		)
	Projected Benefit Obligation at End of Year	407				330			81			74
	Change in Plan Assets
	Fair Value of Plan Assets at Beginning of Year	307				275			10			7
	Actual Return on Plan Assets	35				27			1			1
	Benefits Paid	(16		)		(17		)	(5		)	(4		)
	Employer Contributions (1)	9				22			6			6
	Fair Value of Plan Assets at End of Year	335				307			12			10
	Funded Status at End of Year	$	(72	)		$	(23	)	$	(69	)	$	(64	)
	(1)	In 2015, TEP expects to contribute $23 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
		Years Ended December 31,
		2014				2013			2014			2013
		Millions of Dollars
	Net Loss	$	118			$	74		$	11		$	6
	Prior Service Cost (Benefit)	4				—			(2		)	(2		)
	The accumulated benefit obligation aggregated for all pension plans is $365 million at December 31, 2014 and $297 million at December 31, 2013.
	Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
		December 31,
		2014				2013
		Millions of Dollars
	Accumulated Benefit Obligation at End of Year	$	365			$	13
	Fair Value of Plan Assets at End of Year	335				—
	Only the SERP, which is unfunded, had accumulated benefit obligations in excess of plan assets at December 31, 2013. Due to decreases in discount rates, and changes in mortality projections which reflect a longer life expectancy, all of our plans had accumulated benefit obligations in excess of plan assets at December 31, 2014.
	Net periodic benefit plan cost includes the following components:
		Pension Benefits										Other Retiree Benefits
		Year Ended December 31,
		2014				2013			2012			2014			2013			2012
		Millions of Dollars
Service Cost	$	10			$	11		$	9		$	4		$	3		$	3
Interest Cost	16				14			15			3			3			3
Expected Return on Plan Assets	(21		)		(19		)	(17		)	(1		)	(1		)	—
Actuarial Loss Amortization	3				8			7			—			—			—
Net Periodic Benefit Cost	$	8			$	14		$	14		$	6		$	5		$	6
Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:
	Pension Benefits
	2014							2013						2012
	Regulatory				AOCI			Regulatory			AOCI			Regulatory			AOCI
	Asset							Asset						Asset
	Millions of Dollars
Current Year Actuarial (Gain) Loss	$	49			$	3		$	(42	)	$	(1	)	$	28		$	1
Amortization of Actuarial Gain (Loss)	(3		)		—			(8		)	—			(7		)	—
Total Recognized (Gain) Loss	$	46			$	3		$	(50	)	$	(1	)	$	21		$	1
	Other Retiree Benefits
	2014				2013			2012
	Regulatory				Regulatory			Regulatory
	Asset				Asset			Asset
	Millions of Dollars
Current Year Actuarial (Gain) Loss	$	5			$	(6	)	$	2
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 will amortize $7 million estimated net loss and less than $0.5 million prior service credit from other regulatory assets and less than $0.5 million net loss and less than $0.5 million prior service cost from AOCI into net periodic benefit cost in 2015. Less than $0.5 million estimated net loss and less than $0.5 million prior service benefit for the other retiree benefit plan will be amortized from other regulatory assets into net periodic benefit cost in 2015.
	Pension Benefits				Other Retiree
					Benefits
	2014		2013		2014		2013
Weighted-Average Assumptions Used to Determine
Benefit Obligations as of December 31,
Discount Rate	4.1 - 4.2%		5.0% - 5.1%		3.90%		4.70%
Rate of Compensation Increase	3.00%		3.00%		N/A		N/A
	Pension Benefits						Other Retiree Benefits
	2014		2013		2012		2014	2013		2012
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate	5.0% - 5.1%		4.1% - 4.1%		4.9% - 5.0%		4.70%	3.80%		4.70%
Rate of Compensation Increase	3.00%		3.00%		3.00%		N/A	N/A		N/A
Expected Return on Plan Assets	7.00%		7.00%		7.00%		7.00%	7.00%		7.00%
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 25th percentile to the 75th 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 assumed health care cost trend rates follow:
	December 31,
	2014		2013
Health Care Cost Trend Rate Assumed for Next Year	6.70%		6.70%
Ultimate Health Care Cost Trend Rate Assumed	4.50%		4.50%
Year that the Rate Reaches the Ultimate Trend Rate	2027		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, 2014, amounts:
	One-Percentage-				One-Percentage-
	Point Increase				Point Decrease
	Millions of Dollars
Effect on Total Service and Interest Cost Components	$	1			$	1
Effect on Retiree Benefit Obligation	7				6
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:
	2014			2013
Asset Category
Equity Securities	48	%		50	%
Fixed Income Securities	43	%		40	%
Real Estate	7	%		7	%
Other	2	%		3	%
Total	100	%		100	%
The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:
	Fair Value Measurements of Pension Assets
	December 31, 2014
	Quoted Prices				Significant Other			Significant			Total
	in Active				Observable			Unobservable
	Markets				Inputs			Inputs
	(Level 1)				(Level 2)			(Level 3)
	Millions of Dollars
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
	Fair Value Measurements of Pension Assets
	December 31, 2013
	Level 1				Level 2			Level 3			Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1			$	—		$	—		$	1
Equity Securities:											—
United States Large Cap	—				76			—			76
United States Small Cap	—				16			—			16
Non-United States	—				62			—			62
Fixed Income	—				124			—			124
Real Estate	—				7			14			21
Private Equity	—				—			7			7
Total	$	1			$	285		$	21		$	307
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 in 2014 and comprising 85% in 2013.
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
The following tables set 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.
	Year Ended
	December 31, 2014
	Private				Real Estate			Total
	Equity
	Millions of Dollars
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
	Year Ended
	December 31, 2013
	Private				Real Estate			Total
	Equity
	Millions of Dollars
Beginning Balance at January 1, 2013	$	6			$	13		$	19
Actual Return on Plan Assets:
Assets Held at Reporting Date	1				1			2
Ending Balance at December 31, 2013	$	7			$	14		$	21
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, 2014 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.
	TEP Plans		VEBA Trust
Fixed Income	41%		38%
United States Large Cap	24%		39%
Non-United States Developed	15%		7%
Real Estate	8%		—%
United States Small Cap	5%		5%
Non-United States Emerging	5%		9%
Private Equity	2%		—%
Cash/Treasury Bills	—%		2%
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, 2014, the fair value of VEBA trust assets was $12 million, of which $4 million were fixed income investments and $8 million were equities. As of December 31, 2013, the fair value of VEBA trust assets was $10 million, of which $4 million were fixed income investments and $6 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.
	2015				2016			2017			2018			2019			2020-2024
	Millions of Dollars
Pension Benefits	$	17			$	17		$	19		$	20		$	21		$	121
Other Retiree Benefits	5				5			5			5			6			33
One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million.
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 each of 2014, 2013, and 2012.

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION
	CASH PAYMENTS
		Years Ended December 31,
		2014			2013			2012
		Thousands of Dollars
	Interest Paid, Net of Amounts Capitalized	$	(82,653	)	$	(52,589	)	(52,125	)
	Income Taxes Paid	—			—			(1,796	)
	NON-CASH TRANSACTIONS
	In 2014, the following non-cash transactions occurred:
	•	In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase leased interests in April 2015. See Note 5 of Notes to Consolidated Financial Statements.
	In 2013, the following non-cash transactions occurred:
	•	TEP recorded an increase of $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in December 2014 and January 2015.
	•	In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit of TEP. The proceeds were used to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction.
	•	In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP. The proceeds were deposited with the trustee to redeem debt in December 2013. TEP had no cash receipts or payments as a result of this transaction. See Note 5 of Notes to Consolidated Financial Statements.
	In 2012, the following non-cash transactions occurred:
	•	In June 2012, the Industrial Development Authority of Pima County, Arizona issued approximately $16 million of unsecured tax-exempt IDBs. In March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds. In 2012, TEP redeemed the $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP.
	Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
		Years Ended December 31,
		2014			2013			2012
		Thousands of Dollars
	(Decrease)/Increase to Utility Plant Accruals(1)	$	5,138		$	4,995		$	4,813
	Net Cost of Removal of Interim Retirements(2)	12,128			25,182			35,983
	Capital Lease Obligations(3)	1,107			9,039			11,967
	Asset Retirement Obligations(4)	4,117			8,064			789
	(1)	The non-cash additions to Utility Plant represent accruals for capital expenditures.
	(2)	The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.
	(3)	The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.
	(4)	The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

FAIR_VALUE_MEASUREMENTS_AND_DE

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2014
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.
	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.
		Total				Level 1				Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	15			$	15			$	—		$	—		$	—		$	15
	Restricted Cash(1)	2				2				—			—			—			2
	Rabbi Trust Investments(2)	26				—				26			—			—			26
	Energy Contracts - Regulatory Recovery(3)	1				—				—			1			(1		)	—
	Energy Contracts - No Regulatory Recovery(3)	1				—				—			1			(1		)	—
	Total Assets	45				17				26			2			(2		)	43
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(18		)		—				(9		)	(9		)	1			(17		)
	Energy Contracts - No Regulatory Recovery(3)	(1		)		—				—			(1		)	1			—
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—			(1		)	—			(1		)
	Interest Rate Swaps(4)	(5		)		—				(5		)	—			—			(5		)
	Total Liabilities	(25		)		—				(14		)	(11		)	2			(23		)
	Net Total Assets (Liabilities)	$	20			$	17			$	12		$	(9	)	$	—		$	20
		Total				Level 1				Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—		$	—		$	—		$	—
	Restricted Cash(1)	2				2				—			—			—			2
	Rabbi Trust Investments(2)	22				—				22			—			—			22
	Energy Contracts - Regulatory Recovery(3)	2				—				1			1			(1		)	1
	Total Assets	26				2				23			1			(1		)	25
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(2		)		—				—			(2		)	1			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—			(1		)	—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)	—			—			(7		)
	Total Liabilities	(10		)		—				(7		)	(3		)	1			(9		)
	Net Total Assets (Liabilities)	$	16			$	2			$	16		$	(2	)	$	—		$	16
	(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 balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
	(2)	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
	(3)	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 a power sale option (Level 3). These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
	(4)	Interest Rate Swaps still held are valued based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities Industry and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps are included in Derivative Instruments on the balance sheets.
	(5)	All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.
	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. In the first half of 2013, we also used this pricing model to value our power purchase options. Beginning in the third quarter of 2013, the fair value of our power purchase options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the purchase power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented.
	The valuation of our power sale option is a function of observable market variables, regional power and gas prices, as well as the ratio between the two, 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 enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. At December 31, 2014, we have one interest rate swap agreement which expires in January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statements of comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million.
	Energy Contracts - Regulatory Recovery
	We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:
		Year Ended December 31,
		2014				2013				2012
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities	$	(18	)		$	—			$	6
	Realized gains and losses on settled contracts are fully recoverable through the PPFAC.
	Energy Contracts - No Regulatory Recovery
	From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery. In December 2014, TEP entered into a three-year sales option contract. The unrealized gain recorded in Electric Wholesale Sales in 2014 was less than $1 million.
	Derivative Volumes
	At December 31, 2014, we have energy contracts that will settle through the fourth quarter of 2017. The volumes associated with our energy contracts were as follows:
		December 31, 2014			December 31, 2013
Power Contracts GWh	2,604			779
Gas Contracts GBtu	19,932			9,615
Level 3 Fair Value Measurements
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
			Fair Value at
	Valuation		31-Dec-14									Range of
	Approach		Assets				Liabilities				Unobservable Inputs	Unobservable Input
			Millions of Dollars									Minimum			Maximum
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		%	53.29		%
Level 3 Energy Contracts			$	2			$	(11	)
			Fair Value at
	Valuation		31-Dec-13									Range of
	Approach		Assets				Liabilities				Unobservable Inputs	Unobservable Input
			Millions of Dollars									Minimum			Maximum
Forward Power Contracts	Market approach		$	—			$	(3	)		Market price per MWh	$	27		$	48.25
Gas Option Contracts	Option model		1				—				Market price per MMbtu	$	3.88		$	4.32
											Gas volatility	25.05		%	35.07		%
Level 3 Energy Contracts			$	1			$	(3	)
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. Generally, the impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, rather than in the income statement.
The following tables present 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,
		2014				2013
		Millions of Dollars
Balances at Beginning of Year		$	(2	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(8		)		(2		)
Settlements		1				—
Balances at End of Year		$	(9	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(8	)		$	(1	)
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, 2014, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $21 million, compared with $5 million at December 31, 2013. At December 31, 2014, TEP had no cash collateral posted and less than $1 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $21 million.
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:
•	The carrying amounts of our current maturities of long-term debt and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.
•	For Investment in Lease Equity, we estimated the price at which an investor would realize a target internal rate of return. Our estimates included: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumed a residual value based on an appraisal of Springerville Unit 1 conducted in 2011. No impairment has been recorded as TEP expects to recover the full carrying value in retail rates. The balance was transferred to Plant in Service upon the December 2014 purchase of an additional undivided interest in Springerville Unit 1. See Note 3 of Notes to Consolidated Financial Statements.
•	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 carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
			31-Dec-14						31-Dec-13
	Fair Value		Carrying			Fair			Carrying			Fair
	Hierarchy		Value			Value			Value			Value
			Millions of Dollars
Assets:
Investment in Lease Equity(1)	Level 3		N/A			N/A			$	36		$	25
Liabilities:
Long-Term Debt	Level 2		1,372			1,457			1,223			1,214
(1)	Balance was transferred to Plant in Service in December 2014.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
INCOME TAXES	INCOME TAXES
	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		Years Ended December 31,
		2014			2013			2012
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	56		$	52		$	37
	State Income Tax Expense, Net of Federal Deduction	7			7			5
	Federal/State Tax Credits	(5		)	(2		)	(1		)
	Allowance for Equity Funds Used During Construction	(2		)	(1		)	(1		)
	Deferred Tax Asset Valuation Allowance	—			2			—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—
	Other	2			1			(1		)
	Total Federal and State Income Tax Expense	$	58		$	48		$	39
	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 TEP 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:
		Years Ended December 31,
		2014			2013			2012
		Millions of Dollars
	Current Tax Expense (Benefit):
	Federal	$	(1	)	$	(8	)	$	(4	)
	State	—			(2		)	(2		)
	Total Current Tax Expense (Benefit)	(1		)	(10		)	(6		)
	Deferred Tax Expense (Benefit):
	Federal	54			47			38
	Federal Investment Tax Credits	(4		)	(1		)	—
	State	9			12			7
	Total Deferred Tax Expense (Benefit)	59			58			45
	Total Federal and State Income Tax Expense	$	58		$	48		$	39
	The significant components of deferred income tax assets and liabilities consist of the following:
		December 31,
		2014			2013
		Millions of Dollars
	Gross Deferred Income Tax Assets:
	Capital Lease Obligations	$	96		$	127
	Net Operating Loss Carryforwards	187			104
	Customer Advances and Contributions in Aid of Construction	19			19
	Alternative Minimum Tax Credit	24			24
	Accrued Postretirement Benefits	23			23
	Emission Allowance Inventory	10			10
	Investment Tax Credit Carryforward	31			6
	Other	54			38
	Total Gross Deferred Income Tax Assets	444			351
	Deferred Tax Assets Valuation Allowance	(2		)	(2		)
	Gross Deferred Income Tax Liabilities:
	Plant – Net	(699		)	(615		)
	Capital Lease Assets – Net	(74		)	(47		)
	Pensions	(27		)	(22		)
	PPFAC	(8		)	(2		)
	Other	(24		)	(20		)
	Total Gross Deferred Income Tax Liabilities	(832		)	(706		)
	Net Deferred Income Tax Liabilities	$	(390	)	$	(357	)
	The net deferred income tax liability on the balance sheets is as follows:
		December 31,
		2014			2013
		Millions of Dollars
	Deferred Income Taxes – Current Assets	$	102		$	71
	Deferred Income Taxes – Noncurrent Liabilities	(492		)	(428		)
	Net Deferred Income Tax Liability	$	(390	)	$	(357	)
	TEP has recorded a $2 million valuation allowance against state tax credit carryforward deferred tax assets at December 31, 2014. Management believes TEP will not produce sufficient taxable income to use all state tax credits before they expire.
	As of December 31, 2014, TEP had the following carryforward amounts:
		Amount			Expiring Year
		Millions of Dollars
	Federal Net Operating Loss	$	507		2031-34
State Net Operating Loss	237			2016-34
State Credits	8			2016-19
Alternative Minimum Tax Credit	24			None
Investment Tax Credits	31			2032-34
Uncertain Tax Positions
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
	December 31,
	2014			2013
	Millions of Dollars
Unrecognized Tax Benefits, Beginning of Year	$	2		$	23
Additions Based on Tax Positions Taken in the Current Year	2			1
Reductions of Positions from Prior Year Based on Tax Authority Ruling	—			(22		)
Unrecognized Tax Benefits, End of Year	$	4		$	2
Unrecognized tax benefits, if recognized, would not reduce income tax expense at December 31, 2013 and December 31, 2014.
TEP recognized a $1 million reduction to interest expense in 2013 and no reduction in 2014. TEP had no interest payable balances at December 31, 2014 and December 31, 2013. We have no penalties accrued in the years presented.
In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources. These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation. As a result of the IRS ruling in the first quarter of 2013, TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.
TEP has been audited by the IRS through tax year 2010. TEP is not currently under audit by any 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.
Tangible Property Regulations
In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. The adoption of these regulations by TEP resulted in a $22 million increase to plant-related deferred tax liabilities and net operating loss deferred tax assets at December 31, 2014.

RECENTLY_ISSUED_ACCOUNTING_PRO

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	12 Months Ended
	Dec. 31, 2014
Disclosure Text Block [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
	In April 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.
	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. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.
	In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP does not expect the adoption of this guidance to have an impact on its disclosures.

QUARTERLY_FINANCIAL_DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2014
Text Block [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		Second		Third		Fourth
		Thousands of Dollars
	2014
	Operating Revenue	$	255,513	$	321,618	$	387,411	$	305,359
	Operating Income	31,999		79,653		84,898		34,138
	Net Income	9,172		38,725		39,644		14,797
	2013
	Operating Revenue	$	247,751	$	304,263	$	371,239	$	273,437
	Operating Income	22,747		53,433		123,177		31,014
	Net Income	1,478		30,787		64,167		4,910

SCHEDULE_II_Valuation_and_Qual

SCHEDULE II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
SCHEDUEL II- VALUATION & QUALIFYING ACCOUNTS	Schedule II—Valuation and Qualifying Accounts
	Allowance for Doubtful Accounts (1)		Beginning		Additions-		Deductions		Ending
			Balance		Charged to				Balance
					Income
			Millions of Dollars
	Year Ended December 31,
	2014		$	5	$	2	$	2	$	5
	2013		5		2		2		5
	2012		14		3		12		5
	Other Reserves (2)		Beginning Balance		Ending Balance
			Millions of Dollars
	Year Ended December 31,
	2014		$	4	$	5
	2013		8		4
	2012		4		8
	(1)	TEP records additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.
	(2)	As the Other Reserves are not individually significant, additions and deductions need not be disclosed. Other reserves are made up of reserves for sales tax audits, litigation matters, and damages billable to third parties.

NATURE_OF_OPERATIONS_AND_SUMMA1

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014							Dec. 31, 2013	Dec. 31, 2012
Text Block [Abstract]
Nature of Operations	Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits and distributes electricity to approximately 415,000 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), which is a leader in the North American electric and gas utility business.
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 of Notes to Consolidated Financial Statements. 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 in the consolidated statements of income. See Note 3 of Notes to Consolidated Financial Statements.
	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 Merger were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis.
	As a result of the Merger, TEP has elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current period presentation.
Reclassification, Policy [Policy Text Block]	REVISION OF BALANCE SHEET AND STATEMENT OF CAPITALIZATION AS OF DECEMBER 31, 2013
	TEP revised its December 31, 2013 balance sheet and statement of capitalization to correct an immaterial error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. The notes that follow have been updated for this revision.
Recently Adopted Accounting Pronouncements	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2014, we adopted accounting guidance that:
	•	requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.
	•	impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.
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. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. 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:
		2014		2013		2012
	Average AFUDC Rates	7.3	%	7.38	%	7.22	%
Average annual depreciation rate	2.99%							3.16%	3.22%
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 items 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 of Notes to Consolidated Financial Statements.
	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—Other on the balance sheets. Restricted cash was $2 million at December 31, 2014 and December 31, 2013.
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.
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 2 and Note 3 of Notes to Consolidated Financial Statements. 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:
		2014		2013		2012
	Average Annual Depreciation Rates	2.99	%	3.16	%	3.22	%
TEP Utility Plant Under Capital Leases	Utility Plant Under Capital Leases
	TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 3 of Notes to Consolidated Financial Statements) and Interest Expense—Capital Leases. The lease terms are described in Note 5 of Notes to Consolidated Financial Statements.
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.
Investments in Lease Debt and Equity	INVESTMENTS IN LEASE EQUITY
	Prior to December 2014, TEP held a 14.1% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 10 of Notes to Consolidated Financial Statements.
	TEP accounted for its equity interest in the Springerville Unit 1 Lease trust using the equity method. In December 2014, following the purchase of an additional undivided interest in Springerville Unit 1, TEP transferred the balance of its investment in lease equity to Plant in Service.
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. 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. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.
	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. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
	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 electricity 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 kWh sales lost due to Energy Efficiency (EE) Standards and Distributed Generation (DG). 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.
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.
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.
Recovery Of Fuel And Purchased Energy Costs	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 of Notes to Consolidated Financial Statements.
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 Electric EE Standards require increasing annual targeted retail Kilowatt-hours (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 of Notes to Consolidated Financial Statements
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 – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due to TEP from ratepayers as these tax benefits reverse. See Note 2 of Notes to Consolidated Financial Statements.
	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 effective July 1, 2013 due to the 2013 TEP Rate Order. 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.
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.
	Cash Flow Hedges
	TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. TEP accounts for cash flow hedges as follows:
	•	The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and
	•	When TEP determines a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.
	We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.
	Energy Contracts - Regulatory Recovery
	TEP is authorized to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC mechanism.
	Energy Contracts - No Regulatory Recovery
	From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery.
	Master Netting Agreements
	We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.
	Normal Purchases and Normal Sales
	We enter into forward energy purchase and sales contracts, including options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.
	Commodity Trading
	We did not engage in trading of derivative financial instruments for the periods presented.
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 sheets. 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 of Notes to Consolidated Financial Statements.

NATURE_OF_OPERATIONS_AND_SUMMA2

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
AFUDC Rates	The average AFUDC rates on regulated construction expenditures are included in the table below:
		2014		2013		2012
	Average AFUDC Rates	7.3	%	7.38	%	7.22	%
Summary Of Average Annual Depreciation Rates For All Utility Plants	Below are the summarized average annual depreciation rates for all utility plant:
		2014		2013		2012
	Average Annual Depreciation Rates	2.99	%	3.16	%	3.22	%

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Regulatory Assets and Liabilities	The following table summarizes regulatory assets and liabilities:
		December 31, 2014			December 31, 2013
		Millions of Dollars
	Regulatory Assets—Current
	Property Tax Deferrals (1)	$	21		$	20
	PPFAC (2)	19			4
	Derivative Instruments (Note 10)	15			1
	LFCR and DSM (2)	8			3
	San Juan Mine Fire Cost Deferral (2)	2			10
	Other Current Regulatory Assets (3)	4			5
	Total Regulatory Assets—Current	69			43
	Regulatory Assets—Noncurrent
	Pension and Other Retiree Benefits (Note 8)	126			75
	Income Taxes Recoverable Through Future Rates (4)	31			22
	PPFAC - Final Mine Reclamation and Retiree Health Care Costs (5)	29			25
	Springerville Lease Purchase Commitment Deferrals (6)	16			2
	Unamortized Loss on Reacquired Debt (7)	6			7
	LFCR (2)	4			—
	Tucson to Nogales Transmission Line (8)	4			5
	Other Regulatory Assets (3)	7			5
	Total Regulatory Assets—Noncurrent	223			141
	Regulatory Liabilities—Current
	RES (2)	(28		)	(22		)
	DSM (2)	(6		)	—
	Fortis Merger Customer Credits (9)	(5		)	—
	Other Current Regulatory Liabilities	—			(2		)
	Total Regulatory Liabilities—Current	(39		)	(24		)
	Regulatory Liabilities—Noncurrent
	Net Cost of Removal for Interim Retirements (10)	(265		)	(254		)
	Deferred Investment Tax Credits (11)	(25		)	(4		)
	Income Taxes Payable through Future Rates (4)	(20		)	(5		)
	Fortis Merger Customer Credits (9)	(11		)	—
	Total Regulatory Liabilities—Noncurrent	(321		)	(263		)
	Total Net Regulatory Assets (Liabilities)	$	(68	)	$	(103	)
	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, 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.
	(1)	Property Taxes are recovered over approximately a six months period as costs are paid, rather than as costs are accrued.
	(2)	See Cost Recovery Mechanisms discussed above.
	(3)	Other regulatory assets include self-insured medical costs and short-term disability costs recovered on a pay-as-you-go or cash basis; San Juan Coal Contract Amendment costs (recovery through 2017); rate case costs (recovery over three years); and environmental compliance costs (recovery over one year).
	(4)	Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. See Note 1 of Notes to Consolidated Financial Statements.
	(5)	Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
	(6)	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 5 of Notes to Consolidated Financial Statements.
	(7)	In accordance with FERC guidelines, when TEP refinances its long-term debt, TEP defers and amortizes losses on reacquired debt over the life of the debt agreement.
	(8)	TEP will request recovery from FERC for the costs incurred to develop a high-voltage transmission line from Tucson to Nogales; the project is not going forward. See Note 6 of Notes to Consolidated Financial Statements
	(9)	Fortis Merger Customer Credits represent credits to be applied to customers’ bills according to the Merger Agreement. These credits will be applied to customer bills each year, October through March for a period of five years. See Note 1 of Notes to Consolidated Financial Statements.
	(10)	Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.
	(11)	The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

UTILITY_PLANT_AND_JOINTLYOWNED1

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Operations [Abstract]
Public Utility Property, Plant, and Equipment	The following table shows Utility Plant in Service by major class:
		December 31,
		2014				2013
		Millions of Dollars
	Plant in Service:
	Electric Generation Plant	$	2,388			$	1,889
	Electric Transmission Plant	898				825
	Electric Distribution Plant	1,398				1,298
	General Plant	338				312
	Intangible Plant - Software Costs (1) (2)	149				141
	Electric Plant Held for Future Use	4				3
	Total Plant in Service	$	5,175			$	4,468
	Utility Plant under Capital Leases(3)	$	667			$	638
	(1)	Unamortized computer software costs were $31 million as of December 31, 2014, and $39 million as of December 31, 2013.
	(2)	The amortization of computer software costs was $17 million in 2014, $14 million in 2013, and $13 million in 2012.
	(3)	In 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5 of Notes to Consolidated Financial Statements.
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,
		2014				2013				2012
		Millions of Dollars
	Lease Expense:
	Interest Expense – Included in:
	Capital Leases	$	10			$	25			$	34
	Operating Expenses – Fuel	1				2				3
	Amortization of Capital Lease Assets – Included in:
	Operating Expenses – Fuel	6				5				4
	Operating Expenses – Amortization	16				15				14
	Total Lease Expense	$	33			$	47			$	55
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 at December 31, 2014, were as follows:
		31-Dec-14
		Annual Depreciation Rate (3)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Electric Generation Plant (1)	3.31%		22
	Electric Transmission Plant	1.48%		32
	Electric Distribution Plant (1)	2.08%		35
	General Plant (1)	5.48%		11
	Intangible Plant (2)	Various		Various
	(1)	In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 2 of Notes to Consolidated Financial Statements.
	(2)	The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life of three to five years for smaller application software. For large enterprise software, we use the remaining life depreciation method. At December 31, 2014, remaining lives ranged from one to six years.
	(3)	The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.
	JOINTLY-OWNED FACILITIES
Schedule of Jointly Owned Utility Plants	At December 31, 2014, TEP was a participant in jointly-owned generating stations and transmission systems as follows:
		Ownership Percentage		Plant in Service				Construction Work in				Accumulated Depreciation		Net Book Value
								Progress
				Millions of Dollars
	San Juan Units 1 and 2	50.00%		$	453			$	8			$	242	$	219
	Navajo Units 1, 2, and 3	7.50%		153				1				112		42
	Four Corners Units 4 and 5	7.00%		104				3				77		30
	Luna Energy Facility	33.30%		55				—				2		53
	Gila River Unit 3	75.00%		186				—				54		132
	Gila River Common Facilities	18.75%		42				—				11		31
	Transmission Facilities	Various		371				21				193		199
	Total			$	1,364			$	33			$	691	$	706
Schedule of Asset Retirement Obligations	The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:
		December 31,
		2014				2013
		Millions of Dollars
	Beginning Balance	$	22			$	14
	Liabilities Incurred	5				—
	Accretion Expense or Regulatory Deferral	1				1
	Revisions to the Present Value of Estimated Cash Flows (1)	—				7
	Ending Balance	$	28			$	22
	(1)	Primarily related to changes in expected retirement dates of generating facilities.

RELATED_PARTY_TRANSACTIONS_REL1

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS (Table)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes related party transactions:
		Years Ended December 31,
		2014		2013		2012
		Millions of Dollars
	Wholesale Sales - TEP to UNS Electric (1)	$	4	$	1	$	2
	Wholesale Sales - UNS Electric to TEP (1)	4		2		1
	Control Area Services - TEP to UNS Electric (2)	3		4		3
	Common Costs - TEP to UNS Energy Affiliates (3)	13		12		12
	Supplemental Workforce - UNS Energy Affiliate to TEP (4)	16		16		17
	Corporate Services - UNS Energy to TEP (5)	14		5		2
	Corporate Services - UNS Energy Affiliates to TEP (6)	1		1		1
	(1)	TEP and UNS Electric sell power to each other at prevailing market prices.
	(2)	TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement.
	(3)	Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
	(4)	SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable.
	(5)	Corporate costs at UNS Energy, such as merger costs and legal and audit fees, 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.
	(6)	All Corporate Services (e.g., finance, accounting, tax, legal, and information technology) and other labor services are directly assigned to the benefiting entity at a fully burdened cost when possible.
	At December 31, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances:
		31-Dec-14		31-Dec-13
		Millions of Dollars
	Receivables from Related Parties
	UNS Electric	$	4	$	3
	UNS Gas	1		2
	UNS Energy	—		1
	Total Due from Related Parties	$	5	$	6
	Payables to Related Parties
	SES	$	2	$	2
	UNS Electric	1		—
	UNS Energy	—		7
	Total Due to Related Parties	$	3	$	9

DEBT_CREDIT_FACILITIES_AND_CAP1

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Interest Rates on TEP's Variable Rate	The following table shows interest rates (exclusive of LOC and remarketing fees) on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents:
		Years Ended December 31,
		2014		2013		2012
	Interest Rates on Bonds:
	Average Interest Rate	0.08%		0.10%		0.17%
	Range of Average Weekly Rates	.05% - 0.13%		0.06% - 0.25%		0.06% - 0.26%
Effect Of Fixing Interest Rates On Amortizing Principal Balances Of Swaps	The swap has the effect of fixing the interest rates on the amortizing principal balances as follows:
	Lease Debt Outstanding at December 31, 2014	Fixed			LIBOR
		Rate			Spread
	Notional Amount $32 million - Effective Date June 2006	5.77	%		1.75	%
Maturities of Long-term Debt	Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
		Long-Term				Capital			Total
		Debt				Lease
		Maturities (1)				Obligations
		Millions of Dollars
	2015	$	—			$	188		$	188
	2016	79				16			95
	2017	—				18			18
	2018	100				11			111
	2019	37				12			49
	Total 2015 - 2019	216				245			461
	Thereafter	1,159				18			1,177
	Less: Imputed Interest	—				(20		)	(20		)
	Total	$	1,375			$	243		$	1,618
	(1)	$115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to the 2010 Credit Agreement, which expires in November 2016, and the TEP 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the 2010 Credit Agreement and 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. The repayment of TEP Unsecured Notes is not reduced by the remaining $2 million original issue discount.

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments	TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases.
		2015		2016		2017		2018		2019		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	76	$	78	$	76	$	49	$	49	$	285	$	613
	Purchased Power	22		7		—		—		—		—		29
	Transmission	6		6		6		6		4		16		44
	Renewable Power Purchase Agreements	45		45		45		45		44		565		789
	RES Performance-Based Incentives	8		8		8		8		8		76		116
	Operating Leases:
	Land Easements and Rights-of-Way	2		1		1		1		2		77		84
	Operating Leases Other	1		1		1		1		1		5		10
	Total Purchase Commitments	$	160	$	146	$	137	$	110	$	108	$	1,024	$	1,685
Schedule of Mercury Emission Control Costs	TEP's share of the estimated costs to comply with the MATS rules includes the following:
	Estimated Mercury Emissions Control Costs:	Navajo		Springerville(1)
		Millions of Dollars
	Capital Expenditures	$	1	$	5
	Annual O&M Expenses	1		1
	(1)	Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
Regional Haze Rules, Schedule of Environmental Loss Contingencies by Site	The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.
	TEP's estimated costs involved in meeting these rules are:
	Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
		Millions of Dollars
	Capital Expenditures	$	28	$	37	$	35	$	12
	Annual O&M Expenses	1		1		2		6-May
	(1)	In August 2014, the EPA published a final FIP wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
	(2)	In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
	(3)	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
	(4)	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. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

PURCHASE_OF_GASFIRED_GENERATIO1

PURCHASE OF GAS-FIRED GENERATION FACILITY PURCHASE OF GAS-FIRED GENERATION FACILITY (Tables)	12 Months Ended
	Dec. 31, 2014
Extraordinary and Unusual Items [Abstract]
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:
		Millions of Dollars
	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 Deferred Credits and Other Liabilities - Other on TEP's balance sheet.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Schedule of Amounts Recognized in Balance Sheet	The pension and other retiree benefit related amounts (excluding tax balances) included on our balance sheet are:
		Pension Benefits								Other Retiree
										Benefits
		Years Ended December 31,
		2014				2013				2014			2013
		Millions of Dollars
	Regulatory Pension Asset Included in Other Regulatory Assets	$	117			$	71			$	9		$	4
	Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)		(1		)		(2		)	(2		)
	Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(71		)		(23		)		(67		)	(62		)
	Accumulated Other Comprehensive Loss (related to SERP)	5				2				—			—
	Net Amount Recognized	$	50			$	49			$	(60	)	$	(60	)
Schedule of Changes in Funded Status	OBLIGATIONS AND FUNDED STATUS
	We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2014 and December 31, 2013. The table below includes all of TEP’s plans. All plans have projected benefit obligations in excess of 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
		Years Ended December 31,
		2014				2013				2014			2013
		Millions of Dollars
	Change in Projected Benefit Obligation
	Benefit Obligation at Beginning of Year	$	330			$	357			$	74		$	77
	Actuarial (Gain) Loss	67				(35		)		5			(5		)
	Interest Cost	16				14				3			3
	Service Cost	10				11				4			3
	Benefits Paid	(16		)		(17		)		(5		)	(4		)
	Projected Benefit Obligation at End of Year	407				330				81			74
	Change in Plan Assets
	Fair Value of Plan Assets at Beginning of Year	307				275				10			7
	Actual Return on Plan Assets	35				27				1			1
	Benefits Paid	(16		)		(17		)		(5		)	(4		)
	Employer Contributions (1)	9				22				6			6
	Fair Value of Plan Assets at End of Year	335				307				12			10
	Funded Status at End of Year	$	(72	)		$	(23	)		$	(69	)	$	(64	)
	(1)	In 2015, TEP expects to contribute $23 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
		Years Ended December 31,
		2014				2013				2014			2013
		Millions of Dollars
	Net Loss	$	118			$	74			$	11		$	6
	Prior Service Cost (Benefit)	4				—				(2		)	(2		)
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	The accumulated benefit obligation aggregated for all pension plans is $365 million at December 31, 2014 and $297 million at December 31, 2013.
	Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
		December 31,
		2014				2013
		Millions of Dollars
	Accumulated Benefit Obligation at End of Year	$	365			$	13
	Fair Value of Plan Assets at End of Year	335				—
	Only the SERP, which is unfunded, had accumulated benefit obligations in excess of plan assets at December 31, 2013. Due to decreases in discount rates, and changes in mortality projections which reflect a longer life expectancy, all of our plans had accumulated benefit obligations in excess of plan assets at December 31, 2014.
Components of Net Periodic Benefit Cost	Net periodic benefit plan cost includes the following components:
		Pension Benefits											Other Retiree Benefits
		Year Ended December 31,
		2014				2013				2012			2014			2013			2012
		Millions of Dollars
	Service Cost	$	10			$	11			$	9		$	4		$	3		$	3
	Interest Cost	16				14				15			3			3			3
	Expected Return on Plan Assets	(21		)		(19		)		(17		)	(1		)	(1		)	—
	Actuarial Loss Amortization	3				8				7			—			—			—
	Net Periodic Benefit Cost	$	8			$	14			$	14		$	6		$	5		$	6
	Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)	The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:
		Pension Benefits
		2014								2013						2012
		Regulatory				AOCI				Regulatory			AOCI			Regulatory			AOCI
		Asset								Asset						Asset
		Millions of Dollars
	Current Year Actuarial (Gain) Loss	$	49			$	3			$	(42	)	$	(1	)	$	28		$	1
	Amortization of Actuarial Gain (Loss)	(3		)		—				(8		)	—			(7		)	—
	Total Recognized (Gain) Loss	$	46			$	3			$	(50	)	$	(1	)	$	21		$	1
		Other Retiree Benefits
		2014				2013				2012
		Regulatory				Regulatory				Regulatory
		Asset				Asset				Asset
		Millions of Dollars
	Current Year Actuarial (Gain) Loss	$	5			$	(6	)		$	2
Schedule Of Weighted Average Assumptions Used To Determine Benefit Obligations At Year End Table
		Pension Benefits				Other Retiree
						Benefits
		2014		2013		2014		2013
	Weighted-Average Assumptions Used to Determine
	Benefit Obligations as of December 31,
	Discount Rate	4.1 - 4.2%		5.0% - 5.1%		3.90%		4.70%
	Rate of Compensation Increase	3.00%		3.00%		N/A		N/A
Schedule Of Weighted Average Assumptions Used To Determine Net Periodic Benefit Cost Table
		Pension Benefits						Other Retiree Benefits
		2014		2013		2012		2014		2013		2012
	Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
	Discount Rate	5.0% - 5.1%		4.1% - 4.1%		4.9% - 5.0%		4.70%		3.80%		4.70%
	Rate of Compensation Increase	3.00%		3.00%		3.00%		N/A		N/A		N/A
	Expected Return on Plan Assets	7.00%		7.00%		7.00%		7.00%		7.00%		7.00%
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 assumed health care cost trend rates follow:
		December 31,
		2014		2013
	Health Care Cost Trend Rate Assumed for Next Year	6.70%		6.70%
	Ultimate Health Care Cost Trend Rate Assumed	4.50%		4.50%
	Year that the Rate Reaches the Ultimate Trend Rate	2027		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, 2014, amounts:
		One-Percentage-				One-Percentage-
		Point Increase				Point Decrease
		Millions of Dollars
	Effect on Total Service and Interest Cost Components	$	1			$	1
	Effect on Retiree Benefit Obligation	7				6
Schedule of Allocation of Plan 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:
		2014			2013
	Asset Category
	Equity Securities	48	%		50	%
	Fixed Income Securities	43	%		40	%
	Real Estate	7	%		7	%
	Other	2	%		3	%
	Total	100	%		100	%
FV Measurements of Pension Plan Assets by FV Hierarchy	The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:
		Fair Value Measurements of Pension Assets
		December 31, 2014
		Quoted Prices				Significant Other				Significant			Total
		in Active				Observable				Unobservable
		Markets				Inputs				Inputs
		(Level 1)				(Level 2)				(Level 3)
		Millions of Dollars
	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
		Fair Value Measurements of Pension Assets
		December 31, 2013
		Level 1				Level 2				Level 3			Total
		Millions of Dollars
	Asset Category
	Cash Equivalents	$	1			$	—			$	—		$	1
	Equity Securities:												—
	United States Large Cap	—				76				—			76
	United States Small Cap	—				16				—			16
	Non-United States	—				62				—			62
	Fixed Income	—				124				—			124
	Real Estate	—				7				14			21
	Private Equity	—				—				7			7
	Total	$	1			$	285			$	21		$	307
	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 in 2014 and comprising 85% in 2013.
	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 Assets and Liabilities	The following tables set 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.
		Year Ended
		December 31, 2014
		Private				Real Estate				Total
		Equity
		Millions of Dollars
	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
		Year Ended
		December 31, 2013
		Private				Real Estate				Total
		Equity
		Millions of Dollars
	Beginning Balance at January 1, 2013	$	6			$	13			$	19
	Actual Return on Plan Assets:
	Assets Held at Reporting Date	1				1				2
	Ending Balance at December 31, 2013	$	7			$	14			$	21
	The following tables present 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,
			2014				2013
			Millions of Dollars
	Balances at Beginning of Year		$	(2	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments		(8		)		(2		)
	Settlements		1				—
	Balances at End of Year		$	(9	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(8	)		$	(1	)
Target Allocation Percentages for Plan Assets	The current target allocation percentages for the major asset categories of the plan as of December 31, 2014 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.
		TEP Plans		VEBA Trust
	Fixed Income	41%		38%
	United States Large Cap	24%		39%
	Non-United States Developed	15%		7%
	Real Estate	8%		—%
	United States Small Cap	5%		5%
	Non-United States Emerging	5%		9%
	Private Equity	2%		—%
	Cash/Treasury Bills	—%		2%
	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.
		2015				2016				2017			2018			2019			2020-2024
		Millions of Dollars
	Pension Benefits	$	17			$	17			$	19		$	20		$	21		$	121
	Other Retiree Benefits	5				5				5			5			6			33

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION Supplemental Cash Flow (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Noncash Investing And Financing Activities Table	Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
		Years Ended December 31,
		2014			2013			2012
		Thousands of Dollars
	(Decrease)/Increase to Utility Plant Accruals(1)	$	5,138		$	4,995		$	4,813
	Net Cost of Removal of Interim Retirements(2)	12,128			25,182			35,983
	Capital Lease Obligations(3)	1,107			9,039			11,967
	Asset Retirement Obligations(4)	4,117			8,064			789
	(1)	The non-cash additions to Utility Plant represent accruals for capital expenditures.
	(2)	The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.
	(3)	The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.
	(4)	The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	CASH PAYMENTS
		Years Ended December 31,
		2014			2013			2012
		Thousands of Dollars
	Interest Paid, Net of Amounts Capitalized	$	(82,653	)	$	(52,589	)	(52,125	)
	Income Taxes Paid	—			—			(1,796	)

FAIR_VALUE_MEASUREMENTS_AND_DE1

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure Text Block [Abstract]
Schedule of Fair Value Measurements of Financial Assets and Liabilities	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.
		Total				Level 1				Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	15			$	15			$	—		$	—		$	—		$	15
	Restricted Cash(1)	2				2				—			—			—			2
	Rabbi Trust Investments(2)	26				—				26			—			—			26
	Energy Contracts - Regulatory Recovery(3)	1				—				—			1			(1		)	—
	Energy Contracts - No Regulatory Recovery(3)	1				—				—			1			(1		)	—
	Total Assets	45				17				26			2			(2		)	43
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(18		)		—				(9		)	(9		)	1			(17		)
	Energy Contracts - No Regulatory Recovery(3)	(1		)		—				—			(1		)	1			—
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—			(1		)	—			(1		)
	Interest Rate Swaps(4)	(5		)		—				(5		)	—			—			(5		)
	Total Liabilities	(25		)		—				(14		)	(11		)	2			(23		)
	Net Total Assets (Liabilities)	$	20			$	17			$	12		$	(9	)	$	—		$	20
		Total				Level 1				Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—		$	—		$	—		$	—
	Restricted Cash(1)	2				2				—			—			—			2
	Rabbi Trust Investments(2)	22				—				22			—			—			22
	Energy Contracts - Regulatory Recovery(3)	2				—				1			1			(1		)	1
	Total Assets	26				2				23			1			(1		)	25
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(2		)		—				—			(2		)	1			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—			(1		)	—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)	—			—			(7		)
	Total Liabilities	(10		)		—				(7		)	(3		)	1			(9		)
	Net Total Assets (Liabilities)	$	16			$	2			$	16		$	(2	)	$	—		$	16
	(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 balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
	(2)	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
	(3)	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 a power sale option (Level 3). These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
	(4)	Interest Rate Swaps still held are valued based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities Industry and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps are included in Derivative Instruments on the balance sheets.
	(5)	All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.
Financial Impact of Energy Contracts	Cash Flow Hedges
	We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. At December 31, 2014, we have one interest rate swap agreement which expires in January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statements of comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million.
	Energy Contracts - Regulatory Recovery
	We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:
		Year Ended December 31,
		2014				2013				2012
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities	$	(18	)		$	—			$	6
	Realized gains and losses on settled contracts are fully recoverable through the PPFAC.
	Energy Contracts - No Regulatory Recovery
	From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery. In December 2014, TEP entered into a three-year sales option contract. The unrealized gain recorded in Electric Wholesale Sales in 2014 was less than $1 million.
Derivative Volumes	At December 31, 2014, we have energy contracts that will settle through the fourth quarter of 2017. The volumes associated with our energy contracts were as follows:
		December 31, 2014			December 31, 2013
	Power Contracts GWh	2,604			779
	Gas Contracts GBtu	19,932			9,615
Quantitative Information Regarding Unobservable Inputs	The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
				Fair Value at
		Valuation		31-Dec-14									Range of
		Approach		Assets				Liabilities				Unobservable Inputs	Unobservable Input
				Millions of Dollars									Minimum			Maximum
	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		%	53.29		%
	Level 3 Energy Contracts			$	2			$	(11	)
				Fair Value at
		Valuation		31-Dec-13									Range of
		Approach		Assets				Liabilities				Unobservable Inputs	Unobservable Input
				Millions of Dollars									Minimum			Maximum
	Forward Power Contracts	Market approach		$	—			$	(3	)		Market price per MWh	$	27		$	48.25
	Gas Option Contracts	Option model		1				—				Market price per MMbtu	$	3.88		$	4.32
												Gas volatility	25.05		%	35.07		%
	Level 3 Energy Contracts			$	1			$	(3	)
	Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. Generally, the impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, rather than in the income statement.
Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities	The following tables set 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.
		Year Ended
		December 31, 2014
		Private				Real Estate				Total
		Equity
		Millions of Dollars
	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
		Year Ended
		December 31, 2013
		Private				Real Estate				Total
		Equity
		Millions of Dollars
	Beginning Balance at January 1, 2013	$	6			$	13			$	19
	Actual Return on Plan Assets:
	Assets Held at Reporting Date	1				1				2
	Ending Balance at December 31, 2013	$	7			$	14			$	21
	The following tables present 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,
			2014				2013
			Millions of Dollars
	Balances at Beginning of Year		$	(2	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments		(8		)		(2		)
	Settlements		1				—
	Balances at End of Year		$	(9	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(8	)		$	(1	)
Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments	The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
				31-Dec-14						31-Dec-13
		Fair Value		Carrying			Fair			Carrying			Fair
		Hierarchy		Value			Value			Value			Value
				Millions of Dollars
	Assets:
	Investment in Lease Equity(1)	Level 3		N/A			N/A			$	36		$	25
	Liabilities:
	Long-Term Debt	Level 2		1,372			1,457			1,223			1,214

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		Years Ended December 31,
		2014			2013			2012
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	56		$	52		$	37
	State Income Tax Expense, Net of Federal Deduction	7			7			5
	Federal/State Tax Credits	(5		)	(2		)	(1		)
	Allowance for Equity Funds Used During Construction	(2		)	(1		)	(1		)
	Deferred Tax Asset Valuation Allowance	—			2			—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—
	Other	2			1			(1		)
	Total Federal and State Income Tax Expense	$	58		$	48		$	39
Schedule Of Income Tax Reconciliation Table	Income tax expense included in the income statements consists of the following:
		Years Ended December 31,
		2014			2013			2012
		Millions of Dollars
	Current Tax Expense (Benefit):
	Federal	$	(1	)	$	(8	)	$	(4	)
	State	—			(2		)	(2		)
	Total Current Tax Expense (Benefit)	(1		)	(10		)	(6		)
	Deferred Tax Expense (Benefit):
	Federal	54			47			38
	Federal Investment Tax Credits	(4		)	(1		)	—
	State	9			12			7
	Total Deferred Tax Expense (Benefit)	59			58			45
	Total Federal and State Income Tax Expense	$	58		$	48		$	39
Schedule of Deferred Tax Assets and Liabilities	The significant components of deferred income tax assets and liabilities consist of the following:
		December 31,
		2014			2013
		Millions of Dollars
	Gross Deferred Income Tax Assets:
	Capital Lease Obligations	$	96		$	127
	Net Operating Loss Carryforwards	187			104
	Customer Advances and Contributions in Aid of Construction	19			19
	Alternative Minimum Tax Credit	24			24
	Accrued Postretirement Benefits	23			23
	Emission Allowance Inventory	10			10
	Investment Tax Credit Carryforward	31			6
	Other	54			38
	Total Gross Deferred Income Tax Assets	444			351
	Deferred Tax Assets Valuation Allowance	(2		)	(2		)
	Gross Deferred Income Tax Liabilities:
	Plant – Net	(699		)	(615		)
	Capital Lease Assets – Net	(74		)	(47		)
	Pensions	(27		)	(22		)
	PPFAC	(8		)	(2		)
	Other	(24		)	(20		)
	Total Gross Deferred Income Tax Liabilities	(832		)	(706		)
	Net Deferred Income Tax Liabilities	$	(390	)	$	(357	)
Summary of Deferred Tax Liability Not Recognized	The net deferred income tax liability on the balance sheets is as follows:
		December 31,
		2014			2013
		Millions of Dollars
	Deferred Income Taxes – Current Assets	$	102		$	71
	Deferred Income Taxes – Noncurrent Liabilities	(492		)	(428		)
	Net Deferred Income Tax Liability	$	(390	)	$	(357	)
Summary Of Details Of Tax Carryforwards Table	As of December 31, 2014, TEP had the following carryforward amounts:
		Amount			Expiring Year
		Millions of Dollars
	Federal Net Operating Loss	$	507		2031-34
	State Net Operating Loss	237			2016-34
	State Credits	8			2016-19
	Alternative Minimum Tax Credit	24			None
	Investment Tax Credits	31			2032-34
Summary of Income Tax Contingencies	A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
		December 31,
		2014			2013
		Millions of Dollars
	Unrecognized Tax Benefits, Beginning of Year	$	2		$	23
	Additions Based on Tax Positions Taken in the Current Year	2			1
	Reductions of Positions from Prior Year Based on Tax Authority Ruling	—			(22		)
	Unrecognized Tax Benefits, End of Year	$	4		$	2

QUARTERLY_FINANCIAL_DATA_Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Schedule of Quarterly Financial Information	comparisons among quarters of a year may not represent overall trends and changes in operations.
		First		Second		Third		Fourth
		Thousands of Dollars
	2014
	Operating Revenue	$	255,513	$	321,618	$	387,411	$	305,359
	Operating Income	31,999		79,653		84,898		34,138
	Net Income	9,172		38,725		39,644		14,797
	2013
	Operating Revenue	$	247,751	$	304,263	$	371,239	$	273,437
	Operating Income	22,747		53,433		123,177		31,014
	Net Income	1,478		30,787		64,167		4,910

NATURE_OF_OPERATIONS_AND_SUMMA3

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	sqmi
	Customer
Disclosure Nature Of Operations And Summary Of Significant Accounting Policies Additional Information [Abstract]
Retail customers	415,000
Area in which subsidiary generates transmits and distributes electricity to retail electric customers	1,155
Restricted Cash and Cash Equivalents, Noncurrent	$2	$2

NATURE_OF_OPERATIONS_AND_SUMMA4

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES FORTIS ACQUISITION OF UNS ENERGY (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 15, 2014
Portion of Net Income Entity can Dividend to Parent	60.00%
Length in Periods of Restrictions On Payment Of Dividends (in Years)	5
Required Equity Capitalization for Regulated Utilities Prior to Dividend Payment	50.00%
Required Equity Investment By Acquiring Company Per Merger Settlement Agreement Subject to Regulatory Approval				$220,000,000
Contribution To Parent of Filer	287,000,000
Equity Investment from UNS Energy	225,000,000	0	0
Merger-Related Costs Recorded through Closing of Merger	15,000,000
Share Based Comp Accelerated Vesting Expense	2,000,000
Total share-based compensation expense	5,000,000	3,000,000	2,000,000
Total Bill Credit Refunds Over 5 Years [Member]
Fortis Acquisition Direct Customer Bill Credits	19,000,000
Years Over Which Fortis Acquisition Bill Credit Are Paid	5 years
Bill Credit Refunds in Year 1 [Member]
Fortis Acquisition Direct Customer Bill Credits	6,000,000
Annual Bill Credit Refunds in Years 2 Through 5 [Member]
Fortis Acquisition Direct Customer Bill Credits	3,000,000
Fortis Inc. [Member]
Business Acquisition, Share Price				$60.25
UNS Energy to TEP [Member]
Equity Investment from UNS Energy	$225,000,000

NATURE_OF_OPERATIONS_AND_SUMMA5

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Prior Period Adjustment) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Deferred Income Taxes Current And Noncurrent [Member]
Quantifying Misstatement in Current Year Financial Statements, Amount	$7
Capital Lease Obligation Current And Noncurrent [Member]
Quantifying Misstatement in Current Year Financial Statements, Amount	$18

NATURE_OF_OPERATIONS_AND_SUMMA6

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Nature Of Operations And Summary Of Significant Accounting Policies Afudc Rates [Abstract]
Average AFUDC Rate on Regulated Construction Expenditures	7.30%	7.38%	7.22%

NATURE_OF_OPERATIONS_AND_SUMMA7

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Nature Of Operations And Summary Of Significant Accounting Policies Summary Of Average Annual Depreciation Rates For All Utility Plants [Abstract]
Average annual depreciation rate	2.99%	3.16%	3.22%

NATURE_OF_OPERATIONS_AND_SUMMA8

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (INVESTMENTS IN LEASE EQUITY) (Details)	0 Months Ended
	Nov. 30, 2014	Dec. 29, 2014	Dec. 31, 2014
Springerville Unit One [Member]
Equity Method Investment, Ownership Percentage		14.10%
Equity Method Investment, Ownership Period	Prior to December 2014
Springerville Common Facilities [Member]
Equity Method Investment, Ownership Percentage			7.00%

NATURE_OF_OPERATIONS_AND_SUMMA9

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (RENEWABLE ENERGY EFFICIENCY PROGRAMS) (Details)	12 Months Ended
	Dec. 31, 2014
Renewable Energy and Energy Efficiency Standards [Abstract]
Renewable Energy Target Percentage	15.00%
Distributed Generation Requirement Target Percentage	30.00%
Percentage of Electric Energy Efficiency Standards Target Retail Savings on Sales	22.00%
Renewable Energy Standard, Year by which target is reached	2025
Energy Efficiency Standard, Year by which target retail saving is reached	2020

REGULATORY_MATTERS_Rate_Order_

REGULATORY MATTERS (Rate Order) (Details) (USD $)	1 Months Ended
	Jun. 30, 2013
Schedule of Regulatory Orders [Line Items]
Base rate increase approved	$76,000,000
Expected change in annual depreciation	11,000,000
Environmental compliance adjustor capped rate	$0.00
Retail revenue cap on environmental compliance adjustor	0.25%
Before July 1, 2013 [Member]
Schedule of Regulatory Orders [Line Items]
Change in composite rate	3.32%
After June 30, 2013 [Member] [Member]
Schedule of Regulatory Orders [Line Items]
Change in composite rate	3.00%

REGULATORY_MATTERS_Details

REGULATORY MATTERS (Details) (USD $)	1 Months Ended		12 Months Ended			1 Months Ended	6 Months Ended	10 Months Ended
	Aug. 31, 2014	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2014	Jun. 30, 2013	Apr. 30, 2014
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Mine Fire Cost Deferral			$2,000,000	$10,000,000
Mine Fire Insurance Settlement Proceeds			8,000,000
Environmental Compliance Adjustor Rate			0.000049
Environmental Compliance Adjustor Effective Date			1-May-14
Retail revenue cap on environmental compliance adjustor		0.25%
Regulated Operating Revenue, Other			1,000,000
Energy Efficiency Budget Spending			40,000,000
Approved Energy Efficiency Budget			33,000,000
Energy Efficiency Performance Incentive			2,000,000
Cap on increase in lost fixed cost recovery rate			1.00%
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism			11,327,000	2,171,000	0
Lost Fixed Cost Recovery Requested	5,000,000
LFCR Rate, Retail Revenue for EE	0.41%
LFCR Rate, Retail Revenue for Distributed Generation	0.31%
Amount receivable as return on investment			$1,000,000	$2,000,000
May Through September 2014 [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Purchased Power And Fuel Adjustment Clause Rate						0.001
October 2014 Through March 2015 [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Purchased Power And Fuel Adjustment Clause Rate						0.005
January 2013 through June 2013 [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Purchased Power And Fuel Adjustment Clause Rate							0.0077
July 2013 through April 2014 [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Purchased Power And Fuel Adjustment Clause Rate								0.0014

REGULATORY_MATTERS_Regulatory_

REGULATORY MATTERS (Regulatory Assets and Liabilities) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Disclosure Regulatory Matters Regulatory Assets And Liabilities [Abstract]
Property Tax Deferrals Current	$21,000,000	$20,000,000
PPFAC	19,000,000	4,000,000
Derivative Instruments Regulatory Assets Current	15,000,000	1,000,000
DSM and LFCR Regulatory Assets Current	8,000,000	3,000,000
Mine Fire Cost Deferral	2,000,000	10,000,000
Other Current Regulatory Assets	4,000,000	5,000,000
Regulatory Assets—Current	69,383,000	42,555,000
Pension And Other Postretirement Benefits Noncurrent	126,000,000	75,000,000
Income Taxes Recoverable through Future Revenues	31,000,000	22,000,000
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	29,000,000	25,000,000
Lease Purchase Commitment Deferral	16,000,000	2,000,000
Loss on Reacquired Debt Regulatory Asset	6,000,000	7,000,000
LFCR Regulatory Asset Non-Current	4,000,000	0
Tucson to Nogales Transmission Line	4,000,000	5,000,000
Other Regulatory Assets Noncurrent	7,000,000	5,000,000
Regulatory Assets—Noncurrent	223,192,000	141,030,000
RES	-28,000,000	-22,000,000
DSM Current Regulatory Liability	-6,000,000	0
Customer Credit Current Regulatory Liability	-5,000,000	0
Other Current Regulatory Liabilities Current	0	-2,000,000
Regulatory Liabilities - Current	-38,847,000	-23,701,000
Net Cost of Removal for Interim Retirements	-265,000,000	-254,000,000
Income Taxes Payable through Future Rates	-20,000,000	-5,000,000
Customer Credit Noncurrent Regulatory Liability	-11,000,000	0
Deferred Investment Tax Credit	-25,000,000	-4,000,000
Regulatory Liability, Noncurrent	-321,186,000	-263,270,000
Total Net Regulatory Assets (Liabilities)	($68,000,000)	($103,000,000)

REGULATORY_MATTERS_Regulatory_1

REGULATORY MATTERS (Regulatory Assets and Liabilities Footnotes) (Details)	12 Months Ended
	Dec. 31, 2014
Regulatory Assets [Line Items]
Property Tax Recovery Period	6 months
Recovery Period for Rate Case Costs	3 years
Recovery Period of Environmental Compliance Adjustor	1 year
Minimum [Member]
Regulatory Assets [Line Items]
Expected Life Of Mines	14 years
Maximum [Member]
Regulatory Assets [Line Items]
Expected Life Of Mines	20 years
Total Bill Credit Refunds Over 5 Years [Member]
Regulatory Assets [Line Items]
Years Over Which Fortis Acquisition Bill Credit Are Paid	5 years

UTILITY_PLANT_AND_JOINTLYOWNED2

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for TEP's Generation-Related Capital Leases) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Capital Leases	$10,249,000	$25,140,000	$33,613,000
Interest Expense - Included in:
Total Lease Expense	33,000,000	47,000,000	55,000,000
Operating Expenses - Fuel
Interest Expense - Included in:
Interest Expense	1,000,000	2,000,000	3,000,000
Amortization of Capital Lease Assets	6,000,000	5,000,000	4,000,000
Operating Expenses - Amortization [Member]
Interest Expense - Included in:
Amortization of Capital Lease Assets	$16,000,000	$15,000,000	$14,000,000

UTILITY_PLANT_AND_JOINTLYOWNED3

UTILITY PLANT AND JOINTLY-OWNED FACILITES (TEP's Interests in Jointly-Owned Generating Stations and Transmission Systems) (Detail) (USD $)	Dec. 31, 2014	Jan. 31, 2015
In Millions, unless otherwise specified
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$1,364
Construction Work in Progress	33
Accumulated Depreciation	691
Net Book Value	706
San Juan Units 1 and 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	50.00%
Plant in Service	453
Construction Work in Progress	8
Accumulated Depreciation	242
Net Book Value	219
Navajo Units 1, 2, and 3 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	7.50%
Plant in Service	153
Construction Work in Progress	1
Accumulated Depreciation	112
Net Book Value	42
Four Corners Units 4 and 5 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	7.00%
Plant in Service	104
Construction Work in Progress	3
Accumulated Depreciation	77
Net Book Value	30
Luna Energy Facility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	33.30%
Plant in Service	55
Construction Work in Progress	0
Accumulated Depreciation	2
Net Book Value	53
GIla River Unit 3 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	75.00%
Plant in Service	186
Construction Work in Progress	0
Accumulated Depreciation	54
Net Book Value	132
Gila River Common Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	18.75%
Plant in Service	42
Construction Work in Progress	0
Accumulated Depreciation	11
Net Book Value	31
Transmission Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	371
Construction Work in Progress	21
Accumulated Depreciation	193
Net Book Value	$199
Prior to Purchase of Equity Interest [Member] | Springerville Unit One [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	24.70%
Additional Purchase of Equity Interest | Springerville Unit One [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station		24.80%
Completion of Purchase of Equity Interest [Member] | Springerville Unit One [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station		49.50%

UTILITY_PLANT_AND_JOINTLYOWNED4

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Plant in Service:
Total Plant in Service	$5,175,148,000	$4,467,667,000
Utility Plant under Capital Leases	667,000,000	638,000,000
Electricity Generation Plant, Non-Nuclear [Member]
Plant in Service:
Total Plant in Service	2,388,000,000	1,889,000,000
Electric Transmission Plant [Member]
Plant in Service:
Total Plant in Service	898,000,000	825,000,000
Electric Distribution Plant [Member]
Plant in Service:
Total Plant in Service	1,398,000,000	1,298,000,000
General Plant [Member]
Plant in Service:
Total Plant in Service	338,000,000	312,000,000
Software Costs [Member]
Plant in Service:
Total Plant in Service	149,000,000	141,000,000
Electric Plant Held for Future Use [Member]
Plant in Service:
Total Plant in Service	$4,000,000	$3,000,000

UTILITY_PLANT_AND_JOINTLYOWNED5

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class Footnotes) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Utility Plant And Jointly Owned Facilities Utility Plant In Service By Company And Major Class [Abstract]
Capitalized Computer Software, Gross	$31	$39
Amortization of computer software costs	$17	$14	$13

UTILITY_PLANT_AND_JOINTLYOWNED6

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Generation Plant	22 years
Transmission Plant	32 years
Distribution Plant	35 years
General Plant	11 years
Depreciation Rate	2.99%	3.16%	3.22%
Electric Generation Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	3.31%
Electric Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	1.48%
Electric Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.08%
General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	5.48%

UTILITY_PLANT_AND_JOINTLYOWNED7

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service Footnotes) (Details)	12 Months Ended
	Dec. 31, 2014
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	5 years
Maximum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	1 year
Maximum [Member] | Other Intangible Assets [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	6 years

UTILITY_PLANT_AND_JOINTLYOWNED8

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Asset Retirement Obligations) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Disclosure Utility Plant And Jointly Owned Facilities Schedule Of Asset Retirement Obligations [Abstract]
Beginning Balance	$22	$14
Asset Retirement Obligation, Liabilities Incurred	5	0
Accretion Expense	1	1
Revision to Estimated Cash Flows	0	7
Ending Balance	$28	$22

RELATED_PARTY_TRANSACTIONS_REL2

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Intercompany Allocation Parent to Subsidiary	81.00%
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	$5	$6
Payable to Related Parties	3	9
Tucson Electric Power Company To Uns Electric [Member]
Related Party Transaction [Line Items]
Wholesale Sales from Related Parties	4	1	2
Control Area Services, Other Revenues from Transactions with Related Parties	3	4	3
Uns Electric To Tucson Electric Power Company [Member]
Related Party Transaction [Line Items]
Wholesale Purchases from Related Parties	4	2	1
TEP to UNS Energy Affiliates [Member]
Related Party Transaction [Line Items]
Common Costs Charged to Related Parties	13	12	12
Southwest Energy Solutions, Inc. to TEP [Member]
Related Party Transaction [Line Items]
Supplemental Workforce, Maintenance Costs	16	16	17
UNS Energy Affiliates to TEP [Member]
Related Party Transaction [Line Items]
Corporate Services and Other Labor Charges	1	1	1
UNS Energy to TEP [Member]
Related Party Transaction [Line Items]
Corporate Services and Other Labor Charges	14	5	2
UNS Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	4	3
Payable to Related Parties	1	0
Uns Gas [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	1	2
Uns Energy Corporation [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	0	1
Payable to Related Parties	0	7
Southwest Energy Solutions, Inc. [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payable to Related Parties	$2	$2

DEBT_CREDIT_FACILITIES_AND_CAP2

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Detail) (USD $)	12 Months Ended			1 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2013	Mar. 31, 2014	Sep. 30, 2012	Oct. 31, 2013	Mar. 31, 2013	Dec. 31, 2010	Aug. 31, 2009
Debt Instrument [Line Items]
Repayment of outstanding credit facility	$190,000,000	$78,000,000	$199,000,000
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt face amount					150,000,000	150,000,000		91,000,000
Fixed interest rate of long-term debt	5.75%			6.38%	5.00%	3.85%		4.00%
Debt extinguishment			193,000,000	91,000,000
Variable Rate Demand Obligation [Member]
Debt Instrument [Line Items]
Debt face amount	115,000,000								37,000,000
Debt extinguishment	100,000,000
Derivative amount of hedged item										50,000,000
Fixed rate of interest related to interest rate swap										2.40%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Repayment of outstanding credit facility					90,000,000
Revolving Credit Facility [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Repayment of outstanding credit facility						72,000,000
Minimum [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Fixed interest rate of long-term debt	0.85%
Maximum [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Fixed interest rate of long-term debt	0.95%
Collateralized Mortgage Backed Securities [Member]
Debt Instrument [Line Items]
Debt extinguishment							423,000,000
Amount of 1992 mortgage bonds used to secure letter of credit facilities							423,000,000
Variable Rate Bonds [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt face amount		$100,000,000
Effective interest rate	0.87%	0.95%

DEBT_CREDIT_FACILITIES_AND_CAP3

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Interest Rates on TEP's Variable Rate IDBs) (Detail) (Variable Rate Demand Obligation [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Variable Rate Demand Obligation [Member]
Schedule of Interest Rate [Line Items]
Average Interest Rate	0.08%	0.10%	0.17%
Range of Average weekly interest rate, minimum	0.05%	0.06%	0.06%
Average Weekly Interest Rate Range Maximum	0.13%	0.25%	0.26%

DEBT_CREDIT_FACILITIES_AND_CAP4

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Credit agreements) (Details) (USD $)	12 Months Ended	1 Months Ended	12 Months Ended	1 Months Ended
	Dec. 31, 2014	Apr. 30, 2013	Dec. 31, 2012	Jan. 31, 2015	Dec. 31, 2010	Mar. 31, 2014	Mar. 31, 2013	Sep. 30, 2012	Feb. 25, 2014	Dec. 31, 2013
Unsecured Term Loans [Member]
Debt Instrument [Line Items]
Short-term debt, amount outstanding	$130,000,000
Term loan	0
Short-term debt	130,000,000
Variable Rate Demand Obligation [Member]
Debt Instrument [Line Items]
Debt extinguishment	100,000,000
Debt face amount	115,000,000				37,000,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Outstanding borrowings under the company credit agreement					37,000,000
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt extinguishment		91,000,000	193,000,000
Fixed interest rate of long-term debt	5.75%	6.38%				5.00%	4.00%	3.85%
Debt face amount						150,000,000	91,000,000	150,000,000
Subsequent Event [Member] | Unsecured Term Loans [Member]
Debt Instrument [Line Items]
Short-term debt				130,000,000
Subsequent Event [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Commitment fee percentage									1.00%
Subsequent Event [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt extinguishment				130,000,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	200,000,000
Outstanding borrowings under the company credit agreement	70,000,000
Remaining borrowing capacity	185,000,000
Revolving Credit Facility [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Outstanding borrowings under the company credit agreement	15,000,000									0
Interest rate spread on LIBOR borrowing	1.13%
Interest rate in addition to alternate base rate for alternate base rate loans	0.13%
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Outstanding borrowings under the company credit agreement				70,000,000
Remaining borrowing capacity	170,000,000
Revolving Credit Facility 2014 [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	70,000,000
Revolving Credit Facility 2014 [Member] | Line of Credit 2014 [Member]
Debt Instrument [Line Items]
Outstanding borrowings under the company credit agreement	0
Interest rate spread on LIBOR borrowing	0.75%
Interest rate in addition to alternate base rate for alternate base rate loans	0.75%
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	81,590,000
Letter of Credit [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Outstanding borrowings under the company credit agreement	$1,000,000									$1,000,000
Interest rate spread on LIBOR borrowing	1.13%

DEBT_CREDIT_FACILITIES_AND_CAP5

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (TEP Capital Lease) (Details) (USD $)	12 Months Ended			1 Months Ended		3 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2013	Apr. 30, 2014	Mar. 31, 2014	Jan. 31, 2013	Jan. 31, 2014	Jan. 31, 2015	Aug. 31, 2013
	MW								MW
Debt Instrument [Line Items]
Repayments of long-term capital lease obligations	$165,145,000	$99,621,000	$89,452,000
Generating capacity purchased, in MWs	192
Springerville Unit One Lease [Member]
Debt Instrument [Line Items]
Increase in Capital Lease Obligation				55,000,000
Percentage of interest committed to purchase	0.106
Generating capacity purchased, in MWs	41
Lease arrangement, fair market value purchase price	20,000,000
Increase in utility plant under capital lease				55,000,000
Springerville Coal Handling Facilities Lease [Member]
Debt Instrument [Line Items]
Increase in Capital Lease Obligation					109,000,000
Fixed price to acquire leased interest in facilities					120,000,000
Increase in utility plant under capital lease					109,000,000
Springerville Common Facilities [Member]
Debt Instrument [Line Items]
Number of operating lease	2
Term of contract, renewal						2 years
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 Lease Debt [Member]
Debt Instrument [Line Items]
Proceeds from collection of lease receivables							9,000,000
Equity method investment, aggregate cost		36,000,000
Lease Equity Investment to Plant in Service		36,000,000
Springerville Common Facilities Lease Debt [Member]
Debt Instrument [Line Items]
Derivative basis spread	1.75%	1.75%
Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of long-term capital lease obligations	43,000,000							9,000,000
Subsequent Event [Member] | Springerville Unit One Lease [Member]
Debt Instrument [Line Items]
Generating capacity purchased, in MWs									96
Lease arrangement, fair market value purchase price										46,000,000
SRP [Member] | Springerville Coal Handling Facilities Lease [Member]
Debt Instrument [Line Items]
Sales price of leased interest in facilities	24,000,000
Tri-State [Member] | Springerville Coal Handling Facilities Lease [Member]
Debt Instrument [Line Items]
Sales price of leased interest in facilities	24,000,000
Third Party Owner [Member]
Debt Instrument [Line Items]
Third party owners share of O&M expenses	2,000,000
Third party owners share of capital expenditures	$7,000,000
Additional Purchase of Equity Interest | Springerville Unit One [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station									24.80%
Completion of Purchase of Equity Interest [Member] | Springerville Unit One [Member]
Debt Instrument [Line Items]
Percentage of ownership in generating station									49.50%

DEBT_CREDIT_FACILITIES_AND_CAP6

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Effect of Fixing Interest Rates on Amortizing Principal Balances of Swaps) (Detail) (Springerville Common Facilities Lease Debt [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Instruments And Hedging Activities [Line Items]
Derivative basis spread	1.75%	1.75%
Interest Rate Swap One [Member]
Derivative Instruments And Hedging Activities [Line Items]
Fixed rate of interest related to interest rate swap	5.77%
Derivative basis spread	1.75%
Derivative, notional amount	32

DEBT_CREDIT_FACILITIES_AND_CAP7

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	$188,000,000
2016	95,000,000
2017	18,000,000
2018	111,000,000
2019	49,000,000
Total 2015 - 2019	461,000,000
Thereafter	1,177,000,000
Less: Imputed Interest	-20,000,000
Long-term Debt and Capital Lease Obligations	1,618,000,000
Total	1,372,414,000	1,223,070,000
Capital Lease Obligations [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	188,000,000
2016	16,000,000
2017	18,000,000
2018	11,000,000
2019	12,000,000
Total 2015 - 2019	245,000,000
Thereafter	18,000,000
Less: Imputed Interest	-20,000,000
Total	243,000,000
Long-term Debt [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	0
2016	79,000,000
2017	0
2018	100,000,000
2019	37,000,000
Total 2015 - 2019	216,000,000
Thereafter	1,159,000,000
Less: Imputed Interest	0
Total	$1,375,000,000

DEBT_CREDIT_FACILITIES_AND_CAP8

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt Footnotes) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2010	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Sep. 30, 2012
Variable Rate Demand Obligation [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Debt face amount	$115,000,000	$37,000,000
Springerville Unit 2 Local Furnishings [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Debt face amount	100,000,000
Unsecured Debt [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Debt face amount			150,000,000		91,000,000	150,000,000
Debt discount				$2,000,000

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS COMMITMENTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	$160
2016	146
2017	137
2018	110
2019	108
Thereafter	1,024
Total	1,685
Duration of contract obligation in year	20 years
Rent expense	3	2	2
Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	76
2016	78
2017	76
2018	49
2019	49
Thereafter	285
Total	613
Purchased Power
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	22
2016	7
2017	0
2018	0
2019	0
Thereafter	0
Total	29
Transmission Facilities [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	6
2016	6
2017	6
2018	6
2019	4
Thereafter	16
Total	44
Renewable Power Purchase Agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	45
2016	45
2017	45
2018	45
2019	44
Thereafter	565
Total	789
Percentage of purchase power obligations	100.00%
RES Performance Based Incentives Minimum Commitment [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	8
2016	8
2017	8
2018	8
2019	8
Thereafter	76
Total	116
Land Easements and Rights-of-Way
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	2
2016	1
2017	1
2018	1
2019	2
Thereafter	77
Total	84
Operating Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	1
2016	1
2017	1
2018	1
2019	1
Thereafter	5
Total	$10

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS CONTINGENCIES (Detail) (USD $)	1 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Jan. 31, 2015
Commitments And Contingencies [Line Items]
TEP's share of reclamation costs at expiration dates of the coal supply agreements		$49,000,000
TEP's recorded obligations for final mine reclamation costs		22,000,000	18,000,000
Share of Defaulting Participants' Payment		0
San Juan [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		50.00%
Percentage Of Ownership In Generating Units		20.00%
Four Corner [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		7.00%
TEP accrued an estimated loss related to Four Corners Generating Station		1,000,000
Tucson to Nogales [Member]
Commitments And Contingencies [Line Items]
Transmission line from Tucson to Nogales		60
Transmission Line, in KV		345
Asset Impairment Charges	5,000,000
Regulatory Assets		5,000,000
Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member] | San Juan [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		5,000,000
Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member] | San Juan [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		1,000,000
Assessment for Coal Severance Tax, Coal Supplier [Member] | Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		30,000,000
Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member] | Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		$1,000,000
Springerville Unit One [Member] | Completion of Purchase of Equity Interest [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station				49.50%

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS ENVIRONMENTAL MATTERS (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies [Line Items]
Environmental Costs Recognized, Capitalized in Period	$11		$5	$2
Environmental Remediation Expense	5		8	15
Jointly Owned Utility Plant, Net Ownership Amount	706
One Year In Future [Member]
Commitments And Contingencies [Line Items]
Estimated Environmental Costs To Be Capitalized In Future	28
Estimated Future Annual Operating Costs For Environmental Remediation			4
Two Years In Future [Member] [Member]
Commitments And Contingencies [Line Items]
Estimated Environmental Costs To Be Capitalized In Future	19
Estimated Future Annual Operating Costs For Environmental Remediation	4
Navajo [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	1
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Estimated Capital Expenditure for Selective Catalytic Reduction	28	[1]
Deferred Rent Credit	2
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1
Better Than BART Agreement Year by which to Shut Down One Unit	2020
Better than BART Agreement, Year by which SCR Technology to be Installed	2030
Better than BART Agreement, Year by which Coal Fired Operation will Cease	2044
Estimated Capital Expenditure Related to Installation of Baghouses	28
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses	1
Jointly Owned Utility Plant, Proportionate Ownership Share	7.50%
Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	35	[2]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2
Jointly Owned Utility Plant, Proportionate Ownership Share	7.00%
Springerville [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	5	[3]
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1	[3]
Third-Party Participating in Ownership Interest	50.50%
TEP's Share (in Percentage) of Obligations for Environmental Costs	100.00%
San Juan [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	37	[4]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Jointly Owned Utility Plant, Net Ownership Amount	110
Sundt [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Monitoring Equipment	1
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12	[5]
Jointly Owned Utility Plant, Net Ownership Amount	17
Sundt [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5
Sundt [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	$6
[1]	In August 2014, the EPA published a final FIP wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
[2]	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and
[3]	Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
[4]	In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
[5]	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. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

PURCHASE_OF_GASFIRED_GENERATIO2

PURCHASE OF GAS-FIRED GENERATION FACILITY (Additional Information) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Unusual or Infrequent Item [Line Items]
Utility Plant - Net	$163
Materials and Supplies	2
ARO Obligation Assumed (1)	-1	[1]
Total Purchase Price	164
Entegra, Gila River Generating Station Unit 3 [Member]
Unusual or Infrequent Item [Line Items]
Letter Of Credit Cancelled	15
Total Purchase Price	$164
Tucson Electric Power Company To Uns Electric [Member] | Entegra, Gila River Generating Station Unit 3 [Member]
Unusual or Infrequent Item [Line Items]
Generating capacity of plant in MW	550
Tucson Electric Power Company [Member] | Entegra, Gila River Generating Station Unit 3 [Member]
Unusual or Infrequent Item [Line Items]
Generating capacity of plant in MW	413
Percentage of ownership in Generating Unit	75.00%
Uns Electric Incorporated [Member] | Entegra, Gila River Generating Station Unit 3 [Member]
Unusual or Infrequent Item [Line Items]
Percentage of ownership in Generating Unit	25.00%
Springerville Unit One [Member]
Unusual or Infrequent Item [Line Items]
Generating capacity of plant in MW	195
San Juan Unit Two [Member]
Unusual or Infrequent Item [Line Items]
Generating capacity of plant in MW	170
[1]	1) The ARO obligation was recorded at net present value in Deferred Credits and Other Liabilities - Other on TEP's balance sheet.

EMPLOYEE_BENEFIT_PLANS_Pension

EMPLOYEE BENEFIT PLANS (Pension and Other Retiree Benefit Related Balance Sheet Amounts) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	$117	$71
Accrued Benefit Liability Included in Accrued Employee Expenses	-1	-1
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	-71	-23
Accumulated Other Comprehensive Loss (related to SERP)	5	2
Net Total Amount On Balance Sheet	50	49
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	9	4
Accrued Benefit Liability Included in Accrued Employee Expenses	-2	-2
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	-67	-62
Accumulated Other Comprehensive Loss (related to SERP)	0	0
Net Total Amount On Balance Sheet	($60)	($60)

EMPLOYEE_BENEFIT_PLANS_Change_

EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan, Defined Benefit [Member]
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$330	$357
Actuarial (Gain) Loss	67	-35
Interest Cost	16	14	15
Service Cost	10	11	9
Benefits Paid	-16	-17
Projected Benefit Obligation at End of Year	407	330	357
Change in Plan Assets
Fair Value Beginning Balance	307	275
Actual Return on Plan Assets	35	27
Benefits Paid	-16	-17
Employer Contributions	9	22
Fair Value Ending Balance	335	307	275
Funded Status at End of Year	-72	-23
Other Retiree Benefits [Member]
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	74	77
Actuarial (Gain) Loss	5	-5
Interest Cost	3	3	3
Service Cost	4	3	3
Benefits Paid	-5	-4
Projected Benefit Obligation at End of Year	81	74	77
Change in Plan Assets
Fair Value Beginning Balance	10	7
Actual Return on Plan Assets	1	1
Benefits Paid	-5	-4
Employer Contributions	6	6
Fair Value Ending Balance	12	10	7
Funded Status at End of Year	-69	-64
VEBA Trust [Member] | Other Retiree Benefits [Member]
Change in Plan Assets
Fair Value Beginning Balance	10
Employer Contributions	3	3	3
Fair Value Ending Balance	$12	$10

EMPLOYEE_BENEFIT_PLANS_Expecte

EMPLOYEE BENEFIT PLANS (Expected Pension Contributions For Next Year) (Detail) (Scenario, Forecast [Member], Pension Plan, Defined Benefit [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2015
Scenario, Forecast [Member] | Pension Plan, Defined Benefit [Member]
Funded Status And Amount Recognized In Balance Sheet And Statement Of Operations [Line items]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	$23

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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	$118	$74
Prior Service Cost (Benefit)	4	0
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	11	6
Prior Service Cost (Benefit)	($2)	($2)

EMPLOYEE_BENEFIT_PLANS_Informa

EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Detail) (Pension Plan, Defined Benefit [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
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	$365	$13
Fair Value of Plan Assets at End of Year	$335	$0

EMPLOYEE_BENEFIT_PLANS_Compone1

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$10	$11	$9
Interest Cost	16	14	15
Expected Return on Plan Assets	-21	-19	-17
Actuarial Loss Amortization	3	8	7
Net Periodic Benefit Plan Cost	8	14	14
Other Retiree Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	3	3
Interest Cost	3	3	3
Expected Return on Plan Assets	-1	-1	0
Actuarial Loss Amortization	0	0	0
Net Periodic Benefit Plan Cost	$6	$5	$6

Changes_in_Regulatory_Assets_a

(Changes in Regulatory Assets and Accumulated Comprehensive Income) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial Loss Amortization	$3	$8	$7
Pension Plan, Defined Benefit [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Other Comprehensive Loss (Income), Pension and Other Postretirement Benefit Plans, Net Unamortized Loss (Gain) Arising During Period, before Tax	-49	42	-28
Actuarial Loss Amortization	-3	-8	-7
Total Recognized (Gain) Loss	46	-50	21
Pension Plan, Defined Benefit [Member] | Accumulated Other Comprehensive Loss [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Other Comprehensive Loss (Income), Pension and Other Postretirement Benefit Plans, Net Unamortized Loss (Gain) Arising During Period, before Tax	-3	1	-1
Actuarial Loss Amortization	0	0	0
Total Recognized (Gain) Loss	3	-1	1
Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial Loss Amortization	0	0	0
Other Retiree Benefits [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Other Comprehensive Loss (Income), Pension and Other Postretirement Benefit Plans, Net Unamortized Loss (Gain) Arising During Period, before Tax	$5	($6)	$2

EMPLOYEE_BENEFIT_PLANS_Weighte

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Detail)	Dec. 31, 2014	Dec. 31, 2013
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	4.10%	5.00%
Pension Plan, Defined Benefit [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	4.20%	5.10%
Other Retiree Benefits [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	3.90%	4.70%

EMPLOYEE_BENEFIT_PLANS_Weighte1

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	5.00%	4.10%	4.90%
Pension Plan, Defined Benefit [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	5.10%	4.10%	5.00%
Other Retiree Benefits [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	4.70%	3.80%	4.70%
Expected Return on Plan Assets	7.00%	7.00%	7.00%

EMPLOYEE_BENEFIT_PLANS_Assumed

EMPLOYEE BENEFIT PLANS (Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Health Care Cost Trend Rate Assumed for Next Year	6.70%	6.70%
Ultimate Health Care Cost Trend Rate Assumed	4.50%	4.50%
Year that the Rate Reaches the Ultimate Trend Rate	2027	2027

EMPLOYEE_BENEFIT_PLANS_OnePerc

EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Disclosure Employee Benefit Plans One Percentage Point Change In Assumed Health Care Cost Trend Rates [Abstract]
Effect of one percentage point increase on service and interest cost components	$1
Effect of one percentage point decrease on service and interest cost components	1
Effect on Retiree Benefit Obligation, One-Percentage-Point Increase	7
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease	$6

EMPLOYEE_BENEFIT_PLANS_Percent

EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Detail) (Pension Plan, Defined Benefit [Member])	Dec. 31, 2014	Dec. 31, 2013
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	48.00%	50.00%
Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	43.00%	40.00%
Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	7.00%	7.00%
Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	2.00%	3.00%

EMPLOYEE_BENEFIT_PLANS_Fair_Va

EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Pension Plan Assets By Level) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$23	$21	$19
Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	16	14	13
Level 3 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7	7	6
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	12	10	7
Pension Plan, Defined Benefit [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	335	307	275
Pension Plan, Defined Benefit [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1	1
Pension Plan, Defined Benefit [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	82	76
Pension Plan, Defined Benefit [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	17	16
Pension Plan, Defined Benefit [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	61	62
Pension Plan, Defined Benefit [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	143	124
Pension Plan, Defined Benefit [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	24	21
Pension Plan, Defined Benefit [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7	7
Pension Plan, Defined Benefit [Member] | Level 1 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1	1
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	1
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	311	285
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	82	76
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	16
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	61	62
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	143	124
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	7
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	23	21
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	16	14
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	$7

EMPLOYEE_BENEFIT_PLANS_Reconci

EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Detail) (Level 3 [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	$21	$19
Actual Return on Plan Assets:
Assets Held at Reporting Date	3	2
Purchases, Sales, and Settlements	-1
Fair Value Ending Balance	23	21
Private Equity
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	7	6
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	1
Purchases, Sales, and Settlements	-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	14	13
Actual Return on Plan Assets:
Assets Held at Reporting Date	2	1
Purchases, Sales, and Settlements	0
Fair Value Ending Balance	$16	$14

EMPLOYEE_BENEFIT_PLANS_Target_

EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Detail)	12 Months Ended
	Dec. 31, 2014
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	41.00%
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	2.00%
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_Future_

EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	$17
2016	17
2017	19
2018	20
2019	21
Years 2020-2024	121
Other Retiree Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	5
2016	5
2017	5
2018	5
2019	6
Years 2020-2024	$33

EMPLOYEE_BENEFIT_PLANS_Additio

EMPLOYEE BENEFIT PLANS (Additional Information) (Details) (USD $)	12 Months Ended			252 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2035	Dec. 31, 2015
	plans
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Number of defined benefit pension plans	2
Investment Return Model Best-Estimate Range				20 years
Percentage of net periodic benefit cost that was capitalized	20.00%
Matching 401(k) contributions made	$5	$5	$5
Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	23	21	19
Index value percentage of real estate assets	100.00%	85.00%
Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	335	307	275
Employer Contributions	9	22
Defined Benefit Plan, Accumulated Benefit Obligation	365	297
Effect of plan amendment on obligation			1
Effect of plan amendment on future payments			5
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	23	21
Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	10	7
Employer Contributions	6	6
Effect of plan amendment on obligation			1
Regulatory Asset [Member] | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Future Amortization of Prior Service Credit (Cost)					0.5
Defined Benefit Plan, Future Amortization of Gain (Loss)					-7
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)					0.5
Accumulated Other Comprehensive Income (Loss) [Member] | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Future Amortization of Prior Service Credit (Cost)					-0.5
Defined Benefit Plan, Future Amortization of Gain (Loss)					-0.5
Fixed Income | Pension Plan, Defined Benefit [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	143	124
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]
Defined Benefit Plan, Fair Value of Plan Assets	12	10
Employer Contributions	3	3	3
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	4	4
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	$6
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%

SUPPLEMENTAL_CASH_FLOW_INFORMA2

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2013	Oct. 31, 2013	Apr. 30, 2014	Mar. 31, 2014	Mar. 31, 2013	Sep. 30, 2012
Construction in Progress Expenditures Incurred but Not yet Paid	$5,138,000	$4,995,000	$4,813,000
Net Cost Of Removal Of Interim Retirements	12,128,000	25,182,000	35,983,000
Change In Capital Lease Obligations	1,107,000	9,039,000	11,967,000
Asset Retirement Obligation, Liabilities Incurred	4,117,000	8,064,000	789,000
Unsecured Debt [Member]
Debt face amount							150,000,000	91,000,000	150,000,000
Debt extinguishment			193,000,000	91,000,000
Springerville Unit One Lease [Member]
Increase in Utility Plant under Capital Lease					55,000,000
Increase in Capital Lease Obligation					55,000,000
Springerville Coal Handling Facilities Lease [Member]
Increase in Utility Plant under Capital Lease						109,000,000
Increase in Capital Lease Obligation						109,000,000
Variable Rate Bonds [Member] | Unsecured Debt [Member]
Debt face amount		100,000,000
Pima County IDB [Member] | Unsecured Debt [Member]
Debt extinguishment			16,000,000
Apache County IDB [Member] | Unsecured Debt [Member]
Debt extinguishment			$177,000,000

SUPPLEMENTAL_CASH_FLOW_INFORMA3

SUPPLEMENTAL CASH FLOW INFORMATION (Cash Payments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Elements [Abstract]
Interest Paid, Net of Amounts Capitalized	($82,653)	($52,589)	($52,125)
Income Taxes Paid	$0	$0	($1,796)

FAIR_VALUE_MEASUREMENTS_AND_DE2

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Assets
Cash Equivalent	$15	[1]	$0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	26	[2]	22	[2]
Total Assets	45		26
Liabilities
Total Liabilities	-25		-10
Net Total Assets (Liability)	20		16
Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability	-1
Energy Contracts [Member]
Liabilities
Derivative Liability	-18		-2
Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	-1		-1
Interest Rate Swap [Member]
Liabilities
Derivative Liability	-5		-7
Energy Contracts - No Regulatory Recovery [Member]
Assets
Derivative Assets	1	[3]
Energy Contracts [Member]
Assets
Derivative Assets	1	[3]	2	[3]
Level 1 [Member]
Assets
Cash Equivalent	15	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Total Assets	17		2
Liabilities
Total Liabilities	0		0
Net Total Assets (Liability)	17		2
Level 1 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability	0	[3]
Level 1 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 1 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Assets
Derivative Assets	0	[3]
Level 1 [Member] | Energy Contracts [Member]
Assets
Derivative Assets	0	[3]	0	[3]
Level 2 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	26	[2]	22	[2]
Total Assets	26		23
Liabilities
Total Liabilities	-14		-7
Net Total Assets (Liability)	12		16
Level 2 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability	0	[3]
Level 2 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	-9	[3]	0	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	-5	[4]	-7	[4]
Level 2 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Assets
Derivative Assets	0	[3]
Level 2 [Member] | Energy Contracts [Member]
Assets
Derivative Assets	0	[3]	1	[3]
Level 3 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	2		1
Total Assets	2		1
Liabilities
Derivative Liability	-11		-3
Total Liabilities	-11		-3
Net Total Assets (Liability)	-9		-2
Level 3 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability	-1	[3]
Level 3 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	-9	[3]	-2	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	-1	[3]	-1	[3]
Level 3 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 3 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Assets
Derivative Assets	1	[3]
Level 3 [Member] | Energy Contracts [Member]
Assets
Derivative Assets	1	[3]	1	[3]
Netting [Member]
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Total Assets	-2	[5]	-1	[5]
Liabilities
Total Liabilities	2	[5]	1	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability	1	[3],[5]
Netting [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	1	[3],[5]	1	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4],[5]	0	[4],[5]
Netting [Member] | Energy Contracts - No Regulatory Recovery [Member]
Assets
Derivative Assets	-1	[3],[5]
Netting [Member] | Energy Contracts [Member]
Assets
Derivative Assets	-1	[3],[5]	-1	[3],[5]
Net Fair Value [Member]
Assets
Cash Equivalent	15	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	26	[2]	22	[2]
Total Assets	43		25
Liabilities
Total Liabilities	-23		-9
Net Total Assets (Liability)	20		16
Net Fair Value [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability	0	[3]
Net Fair Value [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	-17	[3]	-1	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	-1	[3]	-1	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	-5	[4]	-7	[4]
Net Fair Value [Member] | Energy Contracts - No Regulatory Recovery [Member]
Assets
Derivative Assets	0	[3]
Net Fair Value [Member] | Energy Contracts [Member]
Assets
Derivative Assets	$0	[3]	$1	[3]
[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 balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
[2]	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
[3]	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 a power sale option (Level 3). These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
[4]	Interest Rate Swaps still held are valued based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities Industry and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps are included in Derivative Instruments on the balance sheets.
[5]	All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

FAIR_VALUE_MEASUREMENTS_AND_DE3

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) (Scenario, Forecast [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2015
Scenario, Forecast [Member]
Derivative [Line Items]
Estimated loss expected to be reclassified to earnings within the next twelve months	$3

FAIR_VALUE_MEASUREMENTS_AND_DE4

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) (USD $)	12 Months Ended			36 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Term of Contract				3 years
Unrealized Gain (Loss) on Energy Contracts	$1
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	($18)	$0	$6

FAIR_VALUE_MEASUREMENTS_AND_DE5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Dec. 31, 2014	Dec. 31, 2013
	GWh	GWh
Power Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	2,604	779
Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	19,932,000,000	9,615,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) (Level 3 [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$2	$1
Derivative Liability	-11	-3
Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	1	0
Derivative Liability	-6	-3
Market Approach Valuation Technique [Member] | Call Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	1
Derivative Liability	-1
Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	0	1
Derivative Liability	($4)	$0
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	22.35	27
Minimum [Member] | Market Approach Valuation Technique [Member] | Call Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	27.75
Market price per MMbtu	2.88
Minimum [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MMbtu	2.72	3.88
Gas volatility	30.80%	25.05%
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	39.05	48.25
Maximum [Member] | Market Approach Valuation Technique [Member] | Call Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	44.94
Market price per MMbtu	4.02
Maximum [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MMbtu	3.26	4.32
Gas volatility	53.29%	35.07%

FAIR_VALUE_MEASUREMENTS_AND_DE7

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning balance		($2)	$0
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities - Derivative Instruments		-8	-2
Settlements		1	0
Ending balance		-9	-2
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period		-8	-1
Transferred amount out of Level 3	$0.50

FAIR_VALUE_MEASUREMENTS_AND_DE8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features	$21,000,000	$5,000,000
Letters of Credit Outstanding, Amount	1,000,000
Collateral Already Posted, Aggregate Fair Value	0
Collateral Held from Counterparties	0
Additional collateral if credit-risk contingent features are triggered	$21,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE9

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Liabilities:
Long-Term Debt	$1,372,414,000	$1,223,070,000
Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-Term Debt	1,372,000,000	1,223,000,000
Carrying Value [Member] | Level 3 [Member]
Assets:
Investment in Lease Equity		36,000,000
Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-Term Debt	1,457,000,000	1,214,000,000
Fair Value [Member] | Level 3 [Member]
Assets:
Investment in Lease Equity		$25,000,000

INCOME_TAXES_INCOME_TAXES_Diff

INCOME TAXES 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 $)	1 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Income Taxes Differences Between Income Tax Expense And Amount Obtained By Multiplying Pre Tax Income By U S Statutory Federal Income Tax Rate [Abstract]
Statutory tax rate		35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$56,000,000	$52,000,000	$37,000,000
State Income Tax Expense, Net of Federal Deduction		7,000,000	7,000,000	5,000,000
Federal/State Tax Credits		-5,000,000	-2,000,000	-1,000,000
Allowance for Funds Used During Construction Income Tax Difference		-2,000,000	-1,000,000	-1,000,000
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		0	2,000,000	0
Investment Tax Credit Basis Difference	-11,000,000	0	-11,000,000	0
Other		2,000,000	1,000,000	-1,000,000
Income Tax Expense (Benefit)		$57,911,000	$47,986,000	$39,109,000

INCOME_TAXES_INCOME_TAXES_Inco

INCOME TAXES INCOME TAXES (Income Tax Expense Included in Income Statements) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current Tax Expense (Benefit)
Federal	($1,000,000)	($8,000,000)	($4,000,000)
State	0	-2,000,000	-2,000,000
Total	-1,000,000	-10,000,000	-6,000,000
Deferred Tax Expense (Benefit)
Federal	54,000,000	47,000,000	38,000,000
State	9,000,000	12,000,000	7,000,000
Investment Tax Credit	-4,000,000	-1,000,000	0
Deferred Income Tax Expense (Benefit)	59,000,000	58,000,000	45,000,000
Income Tax Expense (Benefit)	$57,911,000	$47,986,000	$39,109,000

INCOME_TAXES_INCOME_TAXES_The_

INCOME TAXES INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Gross Deferred Income Tax Assets
Capital Lease Obligations	$96	$127
Net Operating Loss Carryforwards	187	104
Customer Advances and Contributions in Aid of Construction	19	19
Alternative Minimum Tax Credit	24	24
Accrued Postretirement Benefits	23	23
Emission Allowance Inventory	10	10
Deferred Tax Assets Unregulated Investment Losses	31	6
Other	54	38
Gross Deferred Income Tax Assets	444	351
Deferred Tax Assets Valuation Allowance	-2	-2
Gross Deferred Income Tax Liabilities
Plant - Net	-699	-615
Capital Lease Assets - Net	-74	-47
Pensions	-27	-22
PPFAC	-8	-2
Other	-24	-20
Deferred Tax Liabilities, Gross	-832	-706
Deferred Tax Liabilities, Net	($390)	($357)

INCOME_TAXES_INCOME_TAXES_Bala

INCOME TAXES INCOME TAXES (Balance Sheets Display Net Deferred Income Tax Liability) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Disclosure Income Taxes Balance Sheets Display Net Deferred Income Tax Liability [Abstract]
Deferred Income Taxes - Current Assets	$102	$71
Deferred Tax Liabilities, Gross, Noncurrent	-492	-428
Deferred Tax Liabilities, Net	($390)	($357)

INCOME_TAXES_INCOME_TAXES_Summ

INCOME TAXES INCOME TAXES (Summary of Tax Carryforwards) (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	$507
Tax Credits	24
Investment Tax Credits	31
State Tax Jurisdiction [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	237
Tax Credits	$8

INCOME_TAXES_INCOME_TAXES_Addi

INCOME TAXES INCOME TAXES (Additional Information) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Deferred Tax Asset Valuation Allowance	$2,000,000	$2,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	0
Unrecognized Tax Benefits, Interest on Income Taxes Expense	0	1,000,000
Reductions Based on Settlements with Tax Authorities	0	-22,000,000
Change In Deferred Tax Liabilities And Deferred Tax Assets Related To Tangible Property	$22,000,000

INCOME_TAXES_INCOME_TAXES_Unce

INCOME TAXES INCOME TAXES (Uncertain Tax Positions) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Uncertain Tax Positions [Abstract]
Unrecognized Tax Benefits	$4	$2	$23
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	2	1
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	$0	($22)

INCOME_TAXES_Operating_Loss_Ca

INCOME TAXES Operating Loss Carryforwards, Expiration Date (Details)	12 Months Ended
	Dec. 31, 2014
Minimum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Dec-31
Tax Credit Carryforwards, Expiration Date	31-Dec-32
Alternative Minimum Tax Credit Carryforwards, Expiration Date	None
Minimum [Member] | State Tax Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Dec-16
Tax Credit Carryforwards, Expiration Date	31-Dec-16
Maximum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Dec-34
Tax Credit Carryforwards, Expiration Date	31-Dec-34
Alternative Minimum Tax Credit Carryforwards, Expiration Date	None
Maximum [Member] | State Tax Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Dec-34
Tax Credit Carryforwards, Expiration Date	31-Dec-19

QUARTERLY_FINANCIAL_DATA_Summa

QUARTERLY FINANCIAL DATA - Summary of Quarterly Financial Data (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Quarterly Financial Data Summary Of Quarterly Financial Data [Abstract]
Operating Revenue	$305,359	$387,411	$321,618	$255,513	$273,437	$371,239	$304,263	$247,751	$1,269,901	$1,196,690	$1,161,660
Operating Income	34,138	84,898	79,653	31,999	31,014	123,177	53,433	22,747	230,688	230,371	200,487
Net Income (Loss)	$14,797	$39,644	$38,725	$9,172	$4,910	$64,167	$30,787	$1,478

SCHEDULE_II_Valuation_and_Qual1

SCHEDULE II - Valuation and Qualifying Accounts (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance	$5	[1]	$5	[1]	$14	[1]
Additions-Charged to Income	2	[1]	2	[1]	3	[1]
Deductions	2	[1]	2	[1]	12	[1]
Ending Balance	5	[1]	5	[1]	5	[1]
Other Valuation Allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance							4	[2]
Ending Balance	$5	[2]	$4	[2]	$8	[2]	$4	[2]
[1]	(1) TEP records additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.
[2]	(2) As the Other Reserves are not individually significant, additions and deductions need not be disclosed. Other reserves are made up of reserves for sales tax audits, litigation matters, and damages billable to third parties.