Tucson Electric Power 10-Q 7 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 20, 2014
Document Documentand Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Entity Registrant Name	'TUCSON ELECTRIC POWER COMPANY	'
Entity Central Index Key	'0000100122	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'No	'
Entity Current Reporting Status	'Yes	'
Entity Voluntary Filer	'No	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	32,139,434

CONDENCED_CONSOLIDATED_BALANCE

CONDENCED CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Utility Plant	'	'
Plant in Service	$4,675,441	$4,467,667
Utility Plant Under Capital Leases	747,158	637,957
Construction Work in Progress	173,022	180,485
Total Utility Plant	5,595,621	5,286,109
Less Accumulated Depreciation and Amortization	-1,909,448	-1,826,977
Less Accumulated Amortization of Capital Lease Assets	-531,159	-514,677
Total Utility Plant—Net	3,155,014	2,944,455
Investments and Other Property	'	'
Investments in Lease Equity	36,086	36,194
Other	36,201	33,488
Total Investments and Other Property	72,287	69,682
Current Assets	'	'
Cash and Cash Equivalents	28,208	25,335
Accounts Receivable—Customer	110,906	80,211
Unbilled Accounts Receivable	49,743	34,369
Allowance for Doubtful Accounts	-5,136	-4,825
Accounts Receivable—Due from Affiliates	3,281	6,064
Materials and Supplies	80,475	75,200
Deferred Income Taxes—Current	111,593	70,722
Fuel Inventory	39,027	44,027
Regulatory Assets—Current	66,877	42,555
Derivative Instruments	699	2,137
Other	13,923	12,923
Total Current Assets	499,596	388,718
Regulatory and Other Assets	'	'
Regulatory Assets—Noncurrent	162,872	141,030
Derivative Instruments	212	167
Other Assets	20,587	19,233
Total Regulatory and Other Assets	183,671	160,430
Total Assets	3,910,568	3,563,285
Capitalization	'	'
Common Stock Equity	1,017,778	925,923
Capital Lease Obligations	68,424	131,370
Long-Term Debt	1,372,369	1,223,070
Total Capitalization	2,458,571	2,280,363
Current Liabilities	'	'
Current Obligations Under Capital Leases	191,951	186,056
Borrowings Under Revolving Credit Facility	35,000	0
Accounts Payable—Trade	83,571	88,556
Accounts Payable—Due to Affiliates	4,099	9,153
Accrued Taxes Other than Income Taxes	53,230	34,485
Accrued Employee Expenses	18,134	24,454
Regulatory Liabilities—Current	37,125	23,701
Accrued Interest	20,043	22,785
Customer Deposits	20,370	21,354
Derivative Instruments	6,664	5,531
Other	8,420	9,244
Total Current Liabilities	478,607	425,319
Deferred Credits and Other Liabilities	'	'
Deferred Income Taxes—Noncurrent	509,062	428,103
Regulatory Liabilities—Noncurrent	302,912	263,270
Pension and Other Postretirement Benefits	79,911	84,936
Derivative Instruments	3,393	5,161
Other	78,112	76,133
Total Deferred Credits and Other Liabilities	973,390	857,603
Commitments, Contingencies & Environmental Matters (Note 5)	'	'
Total Capitalization and Other Liabilities	$3,910,568	$3,563,285

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating Revenues	'	'	'	'
Electric Retail Sales	$316,387	$310,632	$760,192	$739,147
Electric Wholesale Sales	37,053	26,563	111,692	90,503
Other Revenues	33,971	34,044	92,658	93,603
Total Operating Revenues	387,411	371,239	964,542	923,253
Operating Expenses	'	'	'	'
Fuel	89,199	82,065	225,163	247,417
Purchased Energy	49,902	42,477	125,423	89,815
Transmission and Other PPFAC Recoverable Costs	5,222	4,940	12,683	7,535
Increase (Decrease) to Reflect PPFAC Recovery Treatment	-5,376	-7,992	-20,167	-5,079
Total Fuel and Purchased Energy	138,947	121,490	343,102	339,688
Operations and Maintenance	112,667	79,335	273,784	239,170
Depreciation	31,966	30,311	93,857	87,729
Amortization	6,973	6,118	21,449	24,393
Taxes Other Than Income Taxes	11,960	10,808	35,800	32,916
Total Operating Expenses	302,513	248,062	767,992	723,896
Operating Income	84,898	123,177	196,550	199,357
Other Income (Deductions)	'	'	'	'
Interest Income	7	6	181	14
Other Income	2,024	1,466	6,123	3,904
Other Expense	-7,170	-2,776	-11,979	-7,493
Appreciation (Depreciation) in Fair Value of Investments	-504	731	375	1,864
Total Other Income (Deductions)	-5,643	-573	-5,300	-1,711
Interest Expense	'	'	'	'
Long-Term Debt	15,579	13,848	45,326	42,412
Capital Leases	1,202	6,323	9,048	18,821
Other Interest Expense	104	82	557	-86
Interest Capitalized	-850	-644	-2,878	-1,671
Total Interest Expense	16,035	19,609	52,053	59,476
Income Before Income Taxes	63,220	102,995	139,197	138,170
Income Tax Expense	23,576	38,828	51,656	41,737
Net Income	$39,644	$64,167	$87,541	$96,433

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
Net Income	$39,644	$64,167	$87,541	$96,433
Other Comprehensive Income	'	'	'	'
Net Changes in Fair Value of Cash Flow Hedges:	697	700	1,672	2,156
Supplemental Executive Retirement Plan (SERP) Benefit Amortization:	25	68	74	205
Total Other Comprehensive Income, Net of Taxes	722	768	1,746	2,361
Total Comprehensive Income	$40,366	$64,935	$89,287	$98,794

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
Income Tax Expense in Fair Value of Cash Flow Hedges	$450	$458	$1,117	$1,412
Income Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	'	$42	'	$127

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Cash Flows from Operating Activities	'	'
Net Income	$87,541	$96,433
Depreciation	93,857	87,729
Amortization Expense	21,449	24,393
Amortization of Deferred Debt-Related Costs included in Interest Expense	1,959	1,831
Use of Renewable Energy Credits for Compliance	15,129	11,766
Deferred Income Taxes	53,991	53,381
Pension and Retiree Expense	10,236	14,909
Pension and Retiree Funding	-12,989	-26,118
Share-Based Compensation Expense	5,010	2,239
Allowance for Equity Funds Used During Construction	-4,983	-2,923
LFCR Revenue	-8,350	0
Increase (Decrease) to Reflect PPFAC Recovery Treatment	-20,167	-5,079
Fortis Acquisition Direct Customer Benefit	18,870	0
PPFAC Reduction - 2013 TEP Rate Order	0	3,000
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately[Abstract]	'	'
Accounts Receivable	-45,758	-41,227
Materials and Fuel Inventory	-274	14,955
Accounts Payable	-472	-8,678
Income Taxes	-25	-10,681
Interest Accrued	-3,849	1,008
Taxes Other Than Income Taxes	18,745	17,405
Other	-8,652	19,836
Net Cash Flows – Operating Activities	221,268	254,179
Cash Flows from Investing Activities	'	'
Capital Expenditures	-227,153	-180,451
Purchase of Intangibles—Renewable Energy Credits	-22,047	-17,552
Return of Investments in Springerville Lease Debt	0	9,104
Restricted Cash Released	0	4,500
Other, net	12,883	4,656
Net Cash Flows—Investing Activities	-236,317	-179,743
Cash Flows from Financing Activities	'	'
Proceeds from Borrowings Under Revolving Credit Facility	190,000	78,000
Repayments of Borrowings Under Revolving Credit Facility	-155,000	-78,000
Proceeds from Issuance of Long-Term Debt	149,168	0
Payments of Capital Lease Obligations	-165,145	-99,621
Dividends Paid to UNS Energy	0	-20,000
Payment of Debt Issue/Retirement Costs	-1,652	-1,022
Other, net	551	1,250
Net Cash Flows—Financing Activities	17,922	-119,393
Net Increase (Decrease) in Cash and Cash Equivalents	2,873	-44,957
Cash and Cash Equivalents, Beginning of Year	25,335	79,743
Cash and Cash Equivalents, End of Period	$28,208	$34,786

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
In Thousands, unless otherwise specified
Balances at December 31, 2013 at Dec. 31, 2013	$925,923	$888,971	($6,357)	$49,185	($5,876)
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net Income	87,541	'	'	'	'
Other Comprehensive Loss, net of tax	1,746	'	'	'	'
Other	2,568	2,568	'	'	'
Balances at September 30, 2014 at Sep. 30, 2014	$1,017,778	$891,539	($6,357)	$136,726	($4,130)

NATURE_OF_OPERATIONS_AND_FINAN

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	'
	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. In addition, TEP operates Springerville Generating Station (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 Agricultural Improvement and Power District (SRP). 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
	On December 11, 2013, UNS Energy, the parent of TEP, announced that it had entered into an Agreement and Plan of Merger (Merger) to be acquired by Fortis for $60.25 per share of UNS Energy common stock in cash. The acquisition contemplated by this agreement was completed effective August 15, 2014.
	Prior to completion of the Merger, UNS Energy obtained the approval of its shareholders, the Federal Energy Regulatory Commission (FERC), and the Arizona Corporation Commission (ACC). The ACC's approval was subject to certain stipulations, including, but not limited to, the following:
	•	TEP will provide credits on retail customers' bills totaling $19 million over five years: approximately $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;
	•	TEP, along with UNS Energy and its other affiliated subsidiaries, will adopt certain ring-fencing and corporate governance provisions;
	•	Dividends paid from TEP to UNS Energy cannot exceed 60 percent of TEP's annual net income for a period of five years or until such time that TEP's equity capitalization reaches 50 percent of total capital. The ratios used to determine the dividend restrictions will be calculated each calendar year and reported to the ACC annually beginning on April 1, 2016; and
	•	Fortis making an equity investment totaling $220 million to UNS Energy and its regulated subsidiaries, including TEP. Following the close of the Merger, Fortis exceeded the investment requirement by contributing $37 million to UNS Energy on August 15, 2014 and $200 million to UNS Energy on October 10, 2014. On October 10, 2014, UNS Energy contributed $175 million of the investment 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 include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards.
	SHARE-BASED COMPENSATION EXPENSE
	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 the third quarter of 2014 due to the accelerated vesting of the awards. TEP recorded total share-based compensation expense of $4 million for the three months ended September 30, 2014 and $1 million for the three months ended September 30, 2013. For the nine months ended September 30, 2014 and 2013, TEP recorded $5 million and $3 million of share-based compensation expense, respectively. In August 2014, UNS Energy settled all outstanding share-based compensation awards in cash.
	BASIS OF PRESENTATION
	We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K.
	The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results.
	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 Fortis 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 PRIOR PERIOD BALANCE SHEETS
	TEP revised its December 31, 2013 balance sheet to correct an 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. We do not believe the misclassification was material to the previously issued financial statements.
	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.

REGULATORY_MATTERS

REGULATORY MATTERS	9 Months Ended
	Sep. 30, 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.
	COST RECOVERY MECHANISMS
	Purchased Power and Fuel Adjustment Clause
	In April 2014, the ACC approved a Purchased Power and Fuel Adjustment Clause (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 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 September 30, 2014, TEP has received insurance settlement proceeds of $8 million and expects to receive substantially all of the outstanding balance in the fourth quarter. 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 an Environmental Compliance Adjustor (ECA) to recover the return on and of 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 expects to recognize ECA revenues of less than $1 million in 2014.
	Energy Efficiency Standards
	TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (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. In the first nine months of 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Sales in the TEP Income Statement.
	Lost Fixed Cost Recovery Mechanism
	The Lost Fixed Cost Recovery (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 distributed generation (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.
	TEP recorded, in Electric Retail Sales, LFCR revenues of $8 million in the first nine months of 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 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.

RELATED_PARTY_TRANSACTIONS_REL

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2014
Related Party Transactions [Abstract]	'
RELATED PARTY TRANSACTIONS	'
	RELATED PARTY TRANSACTIONS
	TEP engages in various transactions with affiliated subsidiaries of UNS Energy including UNS Electric, 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 are planning the joint purchase of a generating station unit. See Note 6.
	The following table summarizes related party transactions:
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
		Millions of Dollars
	Wholesale Sales - TEP to UNS Electric (1)	$	2	$	—	$	3	$	1
	Wholesale Sales - UNS Electric to TEP (1)	2		—		3		1
	Control Area Services - TEP to UNS Electric (2)	1		1		2		3
	Common Costs - TEP to UNS Energy Affiliates (3)	3		3		10		9
	Supplemental Workforce - SES to TEP (4)	4		4		12		11
	Corporate Services and Other Labor Charges - TEP to UNS Energy Affiliates (5)	3		4		7		10
	Corporate Services - UNS Energy Affiliates to TEP (5)	—		—		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)	All Corporate Services (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; other costs are allocated using the Massachusetts' Formula, an industry accepted method of allocating common costs to affiliated entities.
	At September 30, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances:
		Balances at
		30-Sep-14		31-Dec-13
		Millions of Dollars
	Receivables from Related Parties
	UNS Electric	$	2	$	3
	UNS Gas	1		2
	UNS Energy	—		1
	Total Due from Related Parties	$	3	$	6
	Payables to Related Parties
	SES	$	3	$	2
	UNS Electric	1		—
	UNS Energy	—		7
	Total Due to Related Parties	$	4	$	9

DEBT_AND_CAPITAL_LEASE_OBLIGAT

DEBT AND CAPITAL LEASE OBLIGATIONS	9 Months Ended
	Sep. 30, 2014
Debt and Capital Lease Obligations [Abstract]	'
DEBT AND CAPITAL LEASE OBLIGATIONS	'
	DEBT AND CAPITAL LEASE OBLIGATIONS
	We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2013 Annual Report on Form 10-K.
	SPRINGERVILLE COAL HANDLING FACILITIES CAPITAL 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 of 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.
	TEP previously 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 Leases were not renewed, TEP would exercise the purchase option under those contracts. 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 September 30, 2014.
	2014 UNSECURED NOTES ISSUED
	In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may redeem the notes prior to September 15, 2043, with a make-whole premium plus accrued interest. After September 15, 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 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.
	TEP CREDIT AGREEMENT
	The TEP Credit Agreement consists of a $200 million revolving credit and LOC facility together with an $82 million LOC facility to support tax-exempt bonds. As of September 30, 2014, there is $149 million available under the revolving credit facility. The TEP Credit Agreement expires in November 2016. As of October 20, 2014, TEP had $185 million available under its revolving credit facility.
	TEP provided, in the second quarter of 2014, a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 6.
	COVENANT COMPLIANCE
	At September 30, 2014, we were in compliance with the terms of our loan and credit agreements.

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	'
	COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
	COMMITMENTS
	In addition to those reported in our 2013 Annual Report on Form 10-K, TEP entered into the following long-term commitments through September 30, 2014:
		2014		2015		2016		2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	—	$	9	$	9	$	10	$	10	$	42	$	80
	Purchased Power	—		18		—		—		—		—		18
	Renewable Power Purchase Agreements (PPA)(2)	6		5		5		5		5		60		86
	Capital Lease Obligations(1)	—		120		—		—		—		—		120
	Total Purchase Commitments	$	6	$	152	$	14	$	15	$	15	$	102	$	304
	(1)	In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 4.
	(2)	In July 2014, TEP entered into a 20-year PPA with a renewable energy generation facility that achieved commercial operation in July 2014. TEP is obligated to purchase 100% of the output from this facility. The amounts in the table also reflect updated estimated annual production for existing contracts which increased the minimum annual payment obligations.
	CONTINGENCIES
	Planned Purchase of Gas-Fired Generation Facility
	In 2013, TEP and UNS Electric, an affiliate of TEP, entered into an agreement to purchase a gas-fired generation facility. See Note 6.
	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.
	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. In August 2014, APS submitted a counteroffer with revised settlement terms. The joint participants have agreed to have the matter stayed until November 2014 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 started settlement negotiations in July 2014. 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 $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $21 million at September 30, 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 most fuel costs, including final reclamation costs, to 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 keep the path approved in the line siting matter 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 September 30, 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 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 (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 will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue 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. A study determined that Four Corners' emission controls are adequate. 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 the Navajo Indian Reservation, 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. BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the BART rules apply to plants built prior to Springerville. 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	$	42	$	35	$	35	$	12
	Annual O&M Expenses	1		1		2		6-May
	-1	In August 2014, the EPA published a final rule approving a better-than-BART plan 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. 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 $43 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 state plan 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) on Units 1 and 4 by January 2016. Corresponding to that action, the EPA withdrew the previously applicable FIP addressing the same requirements. Prior to the shutdown of any units in San Juan, PNM must obtain New Mexico Public Regulation Commission approval. If Unit 2 is retired early, TEP expects to request ACC approval to recover all costs associated with the early closure of the unit. TEP owns 50% of San Juan Unit 2. At September 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $111 million.
	-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 & 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 SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At September 30, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover all the remaining costs of the coal handling facilities.

PLANNED_PURCHASE_OF_GASFIRED_G

PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY	9 Months Ended
	Sep. 30, 2014
Other Commitments [Abstract]	'
PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY	'
	PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY
	In December 2013, TEP and UNS Electric, an affiliate of TEP, entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. In October 2014, the FERC issued an order authorizing the transaction. The closing of the transaction remains subject to certain other closing conditions and finalizing various closing documents. TEP and UNS Electric expect the transaction to close in December 2014.
	In June 2014, TEP provided a letter of credit (LOC) for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. The seller is entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the purchase agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled. In August 2014, Entegra filed a prepackaged Chapter 11 bankruptcy in the U.S. Bankruptcy Court for the District of Delaware. In September 2014, Entegra's Chapter 11 bankruptcy plan was confirmed. TEP does not expect the bankruptcy to impact the purchase of Gila River Unit 3.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	9 Months Ended
	Sep. 30, 2014
Text Block [Abstract]	'
EMPLOYEE BENEFIT PLANS	'
	EMPLOYEE BENEFIT PLANS
	Net periodic benefit plan cost includes the following components:
		Pension Benefits						Other Retiree Benefits
		Three Months Ended September 30,
		2014			2013			2014			2013
		Millions of Dollars
	Service Cost	$	2		$	3		$	1		$	1
	Interest Cost	4			4			—			—
	Expected Return on Plan Assets	(5		)	(5		)	—			—
	Actuarial Loss Amortization	1			2			—			—
	Net Periodic Benefit Cost	$	2		$	4		$	1		$	1
		Pension Benefits						Other Retiree Benefits
		Nine Months Ended September 30,
		2014			2013			2014			2013
		Millions of Dollars
	Service Cost	$	7		$	8		$	3		$	3
	Interest Cost	12			11			2			2
	Expected Return on Plan Assets	(16		)	(14		)	(1		)	(1		)
	Actuarial Loss Amortization	3			6			—			—
	Net Periodic Benefit Cost	$	6		$	11		$	4		$	4

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2014
Text Block [Abstract]	'
SUPPLEMENTAL CASH FLOW INFORMATION	'
	SUPPLEMENTAL CASH FLOW INFORMATION
	NON-CASH TRANSACTIONS
	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 4.
	In August 2013, TEP recorded an increase of $39 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in Springerville Unit 1 in January 2015.
	In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds 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.

FAIR_VALUE_MEASUREMENTS_AND_DE

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2014
Disclosure Text Block [Abstract]	'
FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS	'
	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
	We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.
	FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
	The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Sep-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	10			$	10			$	—			$	—			$	—		$	10
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	25				—				25				—				—			25
	Energy Contracts - Regulatory Recovery(3)	1				—				1				—				(1		)	—
	Total Assets	38				12				26				—				(1		)	37
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(5		)		—				(2		)		(3		)		1			(4		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(4		)		—				(4		)		—				—			(4		)
	Total Liabilities	(10		)		—				(6		)		(4		)		1			(9		)
	Net Total Assets (Liabilities)	$	28			$	12			$	20			$	(4	)		$	—		$	28
		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), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. 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 options.
	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. The interest rate swap agreements expire through 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 and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 11. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $2 million.
	Financial Impact of Energy Contracts
	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:
		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities	$	(6	)		$	(1	)		$	(4	)		$	(2	)
	Realized gains and losses on settled contracts are fully recoverable through the PPFAC. At September 30, 2014, we have energy contracts that will settle through the third quarter of 2017.
	Derivative Volumes
	The volumes associated with our energy contracts were as follows:
			September 30, 2014			December 31, 2013
	Power Contracts GWh		842			779
	Gas Contracts GBtu		20,595			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		30-Sep-14										Range of
	Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Power Contracts	Market approach		$	—			$	(3	)		Market price per MWh		$	27.5			$	43.5
Gas Option Contracts	Option model		—				(1		)		Market price per MMbtu		$	3.67			$	4.24
											Gas volatility		24.88		%		40.62		%
Level 3 Energy Contracts			$	—			$	(4	)
			Fair Value at
	Valuation		31-Dec-13										Range of
	Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
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. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.
The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
		Three Months Ended September 30,
		2014				2013
		Millions of Dollars
Balances at June 30		$	—			$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(4		)		(1		)
Settlements		—				—
Balances at September 30		$	(4	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(2	)		$	—
		Nine Months Ended September 30,
		2014				2013
		Millions of Dollars
Balances at December 31		$	(2	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(3		)		(2		)
Settlements		1				—
Balances at September 30		$	(4	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(2	)		$	(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 provided to the Regulated Utilities; 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 September 30, 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 $17 million. At September 30, 2014 , TEP had no cash collateral posted and less than $1 million LOCs as credit enhancements with its counterparties and did not hold any collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $17 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 estimate the price at which an investor would realize a target internal rate of return. Our estimates include: 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 assumes 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.
•	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:
			30-Sep-14								31-Dec-13
	Fair Value		Carrying				Fair				Carrying				Fair
	Hierarchy		Value				Value				Value				Value
			Millions of Dollars
Assets:
Investment in Lease Equity	Level 3		$	36			$	26			$	36			$	25
Liabilities:
Long-Term Debt	Level 2		1,372				1,444				1,223				1,214

INCOME_TAXES_Income_Tax_Expens

INCOME TAXES (Income Tax Expense)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
INCOME TAXES	'
	INCOME TAXES
	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		Three Months Ended September 30,
		2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	22		$	36
	State Income Tax Expense, Net of Federal Deduction	3			5
	Federal/State Tax Credits	(2		)	(1		)
	Other	1			(1		)
	Total Federal and State Income Tax Expense	$	24		$	39
		Nine Months Ended September 30,
		2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	49		$	48
	State Income Tax Expense, Net of Federal Deduction	6			6
	Federal/State Tax Credits	(4		)	(2		)
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)
	Other	1			1
	Total Federal and State Income Tax Expense	$	52		$	42
	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.

RECLASSIFICATIONS_FROM_ACCUMUL

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT	9 Months Ended
	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]	'
RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT	'
	RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT
	The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income												Affected Line Item in the Income Statement
		Three Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(291	)	$	(296	)	$	(882	)	$	(871	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(451		)	(612		)	(1,649		)	(1,820		)	Interest Expense Capital Leases
	Commodity Contracts	(478		)	(556		)	(621		)	(747		)	Purchased Energy/Purchased Power
	Income Tax Benefit	546			579			1,238			1,360
	Realized Losses on Cash Flow Hedges, Net of Taxes	(674		)	(885		)	(1,914		)	(2,078		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(40		)	(110		)	(119		)	(332		)	Other Expense
	Income Tax Benefit	15			42			45			127
	Amortization, Net of Taxes	(25		)	(68		)	(74		)	(205		)
	Total Reclassifications from Other Comprehensive Income	$	(699	)	$	(953	)	$	(1,988	)	$	(2,283	)

RECENTLY_ISSUED_ACCOUNTING_PRO

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	9 Months Ended
	Sep. 30, 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.

NATURE_OF_OPERATIONS_AND_FINAN1

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation	'
	BASIS OF PRESENTATION
	We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K.
	The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results.
	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 Fortis 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 Prior Period Balance Sheets	'
	REVISION OF PRIOR PERIOD BALANCE SHEETS
	TEP revised its December 31, 2013 balance sheet to correct an 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. We do not believe the misclassification was material to the previously issued financial statements.
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.

RELATED_PARTY_TRANSACTIONS_REL1

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS (Table)	9 Months Ended
	Sep. 30, 2014
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions	'
	The following table summarizes related party transactions:
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
		Millions of Dollars
	Wholesale Sales - TEP to UNS Electric (1)	$	2	$	—	$	3	$	1
	Wholesale Sales - UNS Electric to TEP (1)	2		—		3		1
	Control Area Services - TEP to UNS Electric (2)	1		1		2		3
	Common Costs - TEP to UNS Energy Affiliates (3)	3		3		10		9
	Supplemental Workforce - SES to TEP (4)	4		4		12		11
	Corporate Services and Other Labor Charges - TEP to UNS Energy Affiliates (5)	3		4		7		10
	Corporate Services - UNS Energy Affiliates to TEP (5)	—		—		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)	All Corporate Services (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; other costs are allocated using the Massachusetts' Formula, an industry accepted method of allocating common costs to affiliated entities.
	At September 30, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances:
		Balances at
		30-Sep-14		31-Dec-13
		Millions of Dollars
	Receivables from Related Parties
	UNS Electric	$	2	$	3
	UNS Gas	1		2
	UNS Energy	—		1
	Total Due from Related Parties	$	3	$	6
	Payables to Related Parties
	SES	$	3	$	2
	UNS Electric	1		—
	UNS Energy	—		7
	Total Due to Related Parties	$	4	$	9

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments	'
	In addition to those reported in our 2013 Annual Report on Form 10-K, TEP entered into the following long-term commitments through September 30, 2014:
		2014		2015		2016		2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	—	$	9	$	9	$	10	$	10	$	42	$	80
	Purchased Power	—		18		—		—		—		—		18
	Renewable Power Purchase Agreements (PPA)(2)	6		5		5		5		5		60		86
	Capital Lease Obligations(1)	—		120		—		—		—		—		120
	Total Purchase Commitments	$	6	$	152	$	14	$	15	$	15	$	102	$	304
	(1)	In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 4.
	(2)	In July 2014, TEP entered into a 20-year PPA with a renewable energy generation facility that achieved commercial operation in July 2014. TEP is obligated to purchase 100% of the output from this facility. The amounts in the table also reflect updated estimated annual production for existing contracts which increased the minimum annual payment obligations.
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 will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
Regional Haze Rules, Schedule of Environmental Loss Contingencies by Site	'
	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	$	42	$	35	$	35	$	12
	Annual O&M Expenses	1		1		2		6-May
	-1	In August 2014, the EPA published a final rule approving a better-than-BART plan 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. 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 $43 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 state plan 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) on Units 1 and 4 by January 2016. Corresponding to that action, the EPA withdrew the previously applicable FIP addressing the same requirements. Prior to the shutdown of any units in San Juan, PNM must obtain New Mexico Public Regulation Commission approval. If Unit 2 is retired early, TEP expects to request ACC approval to recover all costs associated with the early closure of the unit. TEP owns 50% of San Juan Unit 2. At September 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $111 million.
	-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 & 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 SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At September 30, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover all the remaining costs of the coal handling facilities.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2014
Text Block [Abstract]	'
Components of Net Periodic Benefit Cost	'
	Net periodic benefit plan cost includes the following components:
		Pension Benefits						Other Retiree Benefits
		Three Months Ended September 30,
		2014			2013			2014			2013
		Millions of Dollars
	Service Cost	$	2		$	3		$	1		$	1
	Interest Cost	4			4			—			—
	Expected Return on Plan Assets	(5		)	(5		)	—			—
	Actuarial Loss Amortization	1			2			—			—
	Net Periodic Benefit Cost	$	2		$	4		$	1		$	1
		Pension Benefits						Other Retiree Benefits
		Nine Months Ended September 30,
		2014			2013			2014			2013
		Millions of Dollars
	Service Cost	$	7		$	8		$	3		$	3
	Interest Cost	12			11			2			2
	Expected Return on Plan Assets	(16		)	(14		)	(1		)	(1		)
	Actuarial Loss Amortization	3			6			—			—
	Net Periodic Benefit Cost	$	6		$	11		$	4		$	4

FAIR_VALUE_MEASUREMENTS_AND_DE1

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 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
		30-Sep-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	10			$	10			$	—			$	—			$	—		$	10
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	25				—				25				—				—			25
	Energy Contracts - Regulatory Recovery(3)	1				—				1				—				(1		)	—
	Total Assets	38				12				26				—				(1		)	37
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(5		)		—				(2		)		(3		)		1			(4		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(4		)		—				(4		)		—				—			(4		)
	Total Liabilities	(10		)		—				(6		)		(4		)		1			(9		)
	Net Total Assets (Liabilities)	$	28			$	12			$	20			$	(4	)		$	—		$	28
		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), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. 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	'
	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:
		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities	$	(6	)		$	(1	)		$	(4	)		$	(2	)
	Realized gains and losses on settled contracts are fully recoverable through the PPFAC. At September 30, 2014, we have energy contracts that will settle through the third quarter of 2017.
Derivative Volumes	'
	The volumes associated with our energy contracts were as follows:
			September 30, 2014			December 31, 2013
	Power Contracts GWh		842			779
	Gas Contracts GBtu		20,595			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		30-Sep-14										Range of
		Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Power Contracts	Market approach		$	—			$	(3	)		Market price per MWh		$	27.5			$	43.5
	Gas Option Contracts	Option model		—				(1		)		Market price per MMbtu		$	3.67			$	4.24
												Gas volatility		24.88		%		40.62		%
	Level 3 Energy Contracts			$	—			$	(4	)
				Fair Value at
		Valuation		31-Dec-13										Range of
		Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	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. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.
Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities	'
	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:
			Three Months Ended September 30,
			2014				2013
			Millions of Dollars
	Balances at June 30		$	—			$	(1	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments		(4		)		(1		)
	Settlements		—				—
	Balances at September 30		$	(4	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(2	)		$	—
			Nine Months Ended September 30,
			2014				2013
			Millions of Dollars
	Balances at December 31		$	(2	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments		(3		)		(2		)
	Settlements		1				—
	Balances at September 30		$	(4	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(2	)		$	(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:
				30-Sep-14								31-Dec-13
		Fair Value		Carrying				Fair				Carrying				Fair
		Hierarchy		Value				Value				Value				Value
				Millions of Dollars
	Assets:
	Investment in Lease Equity	Level 3		$	36			$	26			$	36			$	25
	Liabilities:
	Long-Term Debt	Level 2		1,372				1,444				1,223				1,214

INCOME_TAXES_Tables

INCOME TAXES (Tables)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Schedule of Effective Income Tax Rate Reconciliation	'
	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:
		Three Months Ended September 30,
		2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	22		$	36
	State Income Tax Expense, Net of Federal Deduction	3			5
	Federal/State Tax Credits	(2		)	(1		)
	Other	1			(1		)
	Total Federal and State Income Tax Expense	$	24		$	39
		Nine Months Ended September 30,
		2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	49		$	48
	State Income Tax Expense, Net of Federal Deduction	6			6
	Federal/State Tax Credits	(4		)	(2		)
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)
	Other	1			1
	Total Federal and State Income Tax Expense	$	52		$	42

RECLASSIFICATIONS_FROM_ACCUMUL1

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)	9 Months Ended
	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]	'
Reclassifications from Other Comprehensive Income	'
	The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income												Affected Line Item in the Income Statement
		Three Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(291	)	$	(296	)	$	(882	)	$	(871	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(451		)	(612		)	(1,649		)	(1,820		)	Interest Expense Capital Leases
	Commodity Contracts	(478		)	(556		)	(621		)	(747		)	Purchased Energy/Purchased Power
	Income Tax Benefit	546			579			1,238			1,360
	Realized Losses on Cash Flow Hedges, Net of Taxes	(674		)	(885		)	(1,914		)	(2,078		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(40		)	(110		)	(119		)	(332		)	Other Expense
	Income Tax Benefit	15			42			45			127
	Amortization, Net of Taxes	(25		)	(68		)	(74		)	(205		)
	Total Reclassifications from Other Comprehensive Income	$	(699	)	$	(953	)	$	(1,988	)	$	(2,283	)

NATURE_OF_OPERATIONS_AND_FINAN2

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Nature of Operations (Details)	9 Months Ended
	Sep. 30, 2014
	sqmi
	customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Entity Number Of Customers	415,000
Area In Which Subsidiary Generates Transmits And Distributes Electricity To Retail Electric Customers	1,155

NATURE_OF_OPERATIONS_AND_FINAN3

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Fortis Acquisition of UNS Energy (Details) (USD $)	9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014	Aug. 15, 2014	Oct. 10, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Aug. 15, 2014
			Subsequent Event [Member]	Total Bill Credit Refunds Over 5 Years [Member]	Bill Credit Refunds in Year 1 [Member]	Annual Bill Credit Refunds in Years 2 Through 5 [Member]	Fortis Inc. [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Business Acquisition, Share Price	'	'	'	'	'	'	$60.25
Fortis Acquisition Direct Customer Benefit	'	'	'	$19	$6	$3	'
years over which customer benefits are to be paid	'	'	'	5	'	'	'
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	'	'	'	'	'
Initial Equity Investment By Acquiring Company To Parent of Filer	'	37	'	'	'	'	'
Additional post merger equity contribution to parent of entity	'	'	200	'	'	'	'
Proceeds from Contributions from Parent	'	'	175	'	'	'	'
Merger-Related Costs Recorded through Closing of Merger	$15	'	'	'	'	'	'

NATURE_OF_OPERATIONS_AND_FINAN4

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Share-Based Compensation Expense (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Share-based Compensation [Abstract]	'	'	'	'
Share Based Comp Accelerated Vesting Expense	$2	'	'	'
Total share-based compensation expense	$4	$1	$5	$3

NATURE_OF_OPERATIONS_AND_FINAN5

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Revision of Prior Period Balance Sheets (Detail) (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

REGULATORY_MATTERS_COST_RECOVE

REGULATORY MATTERS COST RECOVERY MECHANISMS (Details) (USD $)	1 Months Ended		9 Months Ended		10 Months Ended	1 Months Ended		12 Months Ended
	Aug. 31, 2014	31-May-14	Sep. 30, 2014	Sep. 30, 2013	Apr. 30, 2014	Apr. 30, 2014	Apr. 30, 2014	Dec. 31, 2014
						May Through September 2014 [Member]	October 2014 Through March 2015 [Member]	Scenario, Forecast [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]	'	'	'	'	'	'	'	'
Purchased Power And Fuel Adjustment Clause Rate	'	'	'	'	0.0014	0.001	0.005	'
Mine Fire Cost Deferral	'	'	$10,000,000	'	'	'	'	'
Mine Fire Insurance Settlement Proceeds	'	'	8,000,000	'	'	'	'	'
Environmental Compliance Adjustor Rate	'	0.000049	'	'	'	'	'	'
Regulated Operating Revenue, Other	'	'	'	'	'	'	'	1,000,000
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	'	'	8,350,000	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%	'	'	'	'	'	'	'

RELATED_PARTY_TRANSACTIONS_REL2

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS (Details) (USD $)

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

In Millions, unless otherwise specified

Tucson Electric Power Company To Uns Electric [Member]

Tucson Electric Power Company To Uns Electric [Member]

Tucson Electric Power Company To Uns Electric [Member]

Tucson Electric Power Company To Uns Electric [Member]

Uns Electric To Tucson Electric Power Company [Member]

Uns Electric To Tucson Electric Power Company [Member]

Uns Electric To Tucson Electric Power Company [Member]

Uns Electric To Tucson Electric Power Company [Member]

TEP to UNS Energy Affiliates [Member]

TEP to UNS Energy Affiliates [Member]

TEP to UNS Energy Affiliates [Member]

TEP to UNS Energy Affiliates [Member]

Southwest Energy Solutions, Inc. to TEP [Member]

Southwest Energy Solutions, Inc. to TEP [Member]

Southwest Energy Solutions, Inc. to TEP [Member]

Southwest Energy Solutions, Inc. to TEP [Member]

UNS Energy Affiliates to TEP [Member]

UNS Energy Affiliates to TEP [Member]

UNS Energy Affiliates to TEP [Member]

UNS Energy Affiliates to TEP [Member]

UNS Electric [Member]

UNS Electric [Member]

Uns Gas [Member]

Uns Gas [Member]

Uns Energy Corporation [Member]

Uns Energy Corporation [Member]

Southwest Energy Solutions, Inc. [Member]

Southwest Energy Solutions, Inc. [Member]

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Wholesale Sales from Related Parties

'

'

$2

$0

$3

$1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Wholesale Purchases from Related Parties

'

'

'

'

'

'

2

0

3

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Control Area Services, Other Revenues from Transactions with Related Parties

'

'

1

1

2

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Costs Charged to Related Parties

'

'

'

'

'

'

'

'

'

'

3

3

10

9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Supplemental Workforce, Maintenance Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

4

12

11

'

'

'

'

'

'

'

'

'

'

'

'

Corporate Services and Other Labor Charges

'

'

'

'

'

'

'

'

'

'

3

4

7

10

'

'

'

'

0

0

1

1

'

'

'

'

'

'

'

'

Related Party Transaction, Due from (to) Related Parties [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Receivable from Related Parties

3

6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

3

1

2

0

1

'

'

Payable to Related Parties

$4

$9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1

$0

'

'

$0

$7

$3

$2

DEBT_AND_CAPITAL_LEASE_OBLIGAT1

DEBT AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Details) (Springerville Coal Handling Facilities Lease [Member], USD $)	1 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
		SRP [Member]	Tri-State [Member]
Capital Lease Asset Purchase Commitment [Line Items]	'	'	'
Increase in Capital Lease Obligation	$109	'	'
Fixed price to acquire leased interest in facilities	120	'	'
Increase in utility plant under capital lease	109	'	'
Sales Price of Leased Interest In Facilities	'	$24	$24

DEBT_AND_CAPITAL_LEASE_OBLIGAT2

DEBT AND CAPITAL LEASE OBLIGATIONS (Debt) (Detail) (USD $)	9 Months Ended				1 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Sep. 30, 2014	Sep. 30, 2014	Oct. 20, 2014
			Unsecured Debt [Member]	Unsecured Debt [Member]	Revolving Credit Facility [Member]	Revolving Credit Facility [Member]	Letter of Credit [Member]	Subsequent Event [Member]
								Revolving Credit Facility [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'
Debt Instrument, Face amount	'	'	$150,000,000	$91,000,000	'	'	'	'
Fixed interest rate of long-term debt	'	'	5.00%	'	'	'	'	'
Repayment of outstanding credit facility	155,000,000	78,000,000	'	'	90,000,000	'	'	'
Line of Credit Facility, Maximum Borrowing Capacity	'	'	'	'	'	200,000,000	81,590,000	'
Line of Credit Facility, Remaining Borrowing Capacity	'	'	'	'	'	149,000,000	'	185,000,000
Letters of Credit Outstanding, Amount	$1,000,000	'	'	'	'	'	$15,000,000	'

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS COMMITMENTS (Details) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	$6
2015	152
2016	14
2017	15
2018	15
Thereafter	102
Total	304
Springerville Coal Handling Facilities Lease [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0	[1]
2015	120	[1]
2016	0	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Total	120	[1]
Fuel, Including Transportation	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	9
2016	9
2017	10
2018	10
Thereafter	42
Total	80
Purchased Power	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	18
2016	0
2017	0
2018	0
Thereafter	0
Total	18
Renewable Power Purchase Agreements (PPA)(2)	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	6	[2]
2015	5	[2]
2016	5	[2]
2017	5	[2]
2018	5	[2]
Thereafter	60	[2]
Total	$86	[2]
Duration of Contract Obligation in Year	20
Percentage of Purchase Power Obligations	100.00%
[1]	(1) In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 4.
[2]	(2) In July 2014, TEP entered into a 20-year PPA with a renewable energy generation facility that achieved commercial operation in July 2014. TEP is obligated to purchase 100% of the output from this facility. The amounts in the table also reflect updated estimated annual production for existing contracts which increased the minimum annual payment obligations.

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS CONTINGENCIES (Detail) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2012	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
			San Juan [Member]	Four Corner [Member]	Tucson to Nogales [Member]	Tucson to Nogales [Member]	Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member]	Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member]	Assessment for Coal Severance Tax, Coal Supplier [Member]	Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member]
						mi	San Juan [Member]	San Juan [Member]	Four Corner [Member]	Four Corner [Member]
Commitments And Contingencies [Line Items]	'	'	'	'	'	'	'	'	'	'
Percentage of ownership in generating station	'	'	50.00%	7.00%	'	'	'	'	'	'
Percentage Of Ownership In Generating Units	'	'	20.00%	'	'	'	'	'	'	'
Estimate of Possible Loss Contingency	'	'	'	'	'	'	$5,000,000	$1,000,000	$30,000,000	$1,000,000
TEP accrued an estimated loss related to Four Corners Generating Station	'	'	'	1,000,000	'	'	'	'	'	'
TEP's share of reclamation costs at expiration dates of the coal supply agreements	44,000,000	'	'	'	'	'	'	'	'	'
TEP's recorded obligations for final mine reclamation costs	21,000,000	18,000,000	'	'	'	'	'	'	'	'
Transmission line from Tucson to Nogales	'	'	'	'	'	60	'	'	'	'
Transmission Line, in KV	'	'	'	'	'	345	'	'	'	'
Asset Impairment Charges	'	'	'	'	5,000,000	'	'	'	'	'
Regulatory Assets	'	'	'	'	'	5,000,000	'	'	'	'
Share of Defaulting Participants' Payment	$0	'	'	'	'	'	'	'	'	'

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS ENVIRONMENTAL MATTERS (Detail) (USD $)	9 Months Ended
	Sep. 30, 2014
Navajo [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	$1,000,000
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1,000,000
Estimated Capital Expenditure for Selective Catalytic Reduction	42,000,000	[1]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1,000,000
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	43,000,000
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses	1,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share	7.50%
Four Corner [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Capital Expenditure for Selective Catalytic Reduction	35,000,000	[2]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2,000,000
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	5,000,000	[3]
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1,000,000	[3]
Percentage of Interest Committed to Purchase	0.495
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	35,000,000	[4]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Jointly Owned Utility Plant, Net Ownership Amount	111,000,000
Sundt [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Capital Expenditure for Monitoring Equipment	1,000,000
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12,000,000	[5]
Jointly Owned Utility Plant, Net Ownership Amount	17,000,000
Sundt [Member] | Minimum [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5,000,000
Sundt [Member] | Maximum [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	$6,000,000
[1]	he EPA published a final rule approving a better-than-BART plan 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. 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 $43 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 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
[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 will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue 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 state plan 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) on Units 1 and 4 by January 2016. Corresponding to that action, the EPA withdrew the previously applicable FIP addressing the same requirements. Prior to the shutdown of any units in San Juan, PNM must obtain New Mexico Public Regulation Commission approval. If Unit 2 is retired early, TEP expects to request ACC approval to recover all costs associated with the early closure of the unit. TEP owns 50% of San Juan Unit 2. At September 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $111 million.
[5]	In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At September 30, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover all the remaining costs of the coal handling facilities.

PLANNED_PURCHASE_OF_GASFIRED_G1

PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY (Additional Information) (Details) (Entegra, Gila River Generating Station Unit 3 [Member], USD $)	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Jun. 30, 2014
In Millions, unless otherwise specified	MW	TUCSON ELECTRIC POWER COMPANY	UNS Electric [Member]	Letter of Credit [Member]
		MW	MW
Unusual or Infrequent Item [Line Items]	'	'	'	'
Planned Purchase of Gas-Fired Generation Facility	$219	$164	$55	'
Generating capacity of plant in MW	550	413	137	'
Percentage of ownership in Generating Unit	'	75.00%	25.00%	'
Guaranty Liabilities	'	'	'	$15

EMPLOYEE_BENEFIT_PLANS_Compone

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pension Benefits [Member]	'	'	'	'
Components of Net Periodic Benefit Plan Cost	'	'	'	'
Service Cost	$2	$3	$7	$8
Interest Cost	4	4	12	11
Expected Return on Plan Assets	-5	-5	-16	-14
Amortization of Actuarial (Gain) Loss	1	2	3	6
Net Periodic Benefit Plan Cost	2	4	6	11
Other Retiree Benefits [Member]	'	'	'	'
Components of Net Periodic Benefit Plan Cost	'	'	'	'
Service Cost	1	1	3	3
Interest Cost	0	0	2	2
Expected Return on Plan Assets	0	0	-1	-1
Amortization of Actuarial (Gain) Loss	0	0	0	0
Net Periodic Benefit Plan Cost	$1	$1	$4	$4

Effects_of_Dilutive_Common_Sto

(Effects of Dilutive Common Stock on Weighted-Average Number of Shares) (Detail) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Numerator:	'	'
Net Income	$87,541	$96,433

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013	Aug. 31, 2013	Apr. 30, 2014
	Unsecured Debt [Member]	Unsecured Debt [Member]	Springerville Unit One Lease [Member]	Springerville Coal Handling Facilities Lease [Member]
Increase in Utility Plant under Capital Lease	'	'	$39,000,000	$109,000,000
Debt Instrument, Face amount	150,000,000	91,000,000	'	'
Increase in Capital Lease Obligation	'	'	$39,000,000	$109,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE2

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Assets	'		'
Cash Equivalent	$10	[1]	$0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	25	[2]	22	[2]
Total Assets	38		26
Liabilities	'		'
Liabilities	-10		-10
Net Total Assets (Liability)	28		16
Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-5		-2
Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1		-1
Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-4		-7
Energy Contracts [Member]	'		'
Assets	'		'
Derivative Assets	1	[3]	2	[3]
Level 1 [Member]	'		'
Assets	'		'
Cash Equivalent	10	[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	12		2
Liabilities	'		'
Liabilities	0		0
Net Total Assets (Liability)	12		2
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 [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	25	[2]	22	[2]
Total Assets	26		23
Liabilities	'		'
Liabilities	-6		-7
Net Total Assets (Liability)	20		16
Level 2 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[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	-4	[4]	-7	[4]
Level 2 [Member] | Energy Contracts [Member]	'		'
Assets	'		'
Derivative Assets	1	[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	0		1
Total Assets	0		1
Liabilities	'		'
Derivative Liability	-4		-3
Liabilities	-4		-3
Net Total Assets (Liability)	-4		-2
Level 3 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-3	[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 [Member]	'		'
Assets	'		'
Derivative Assets	0	[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	-1	[5]	-1	[5]
Liabilities	'		'
Liabilities	1	[5]	1	[5]
Net Total Assets (Liability)	0	[5]	0	[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 [Member]	'		'
Assets	'		'
Derivative Assets	-1	[3],[5]	-1	[3],[5]
Net Fair Value [Member]	'		'
Assets	'		'
Cash Equivalent	10	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	25	[2]	22	[2]
Total Assets	37		25
Liabilities	'		'
Liabilities	-9		-9
Net Total Assets (Liability)	28		16
Net Fair Value [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-4	[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	-4	[4]	-7	[4]
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), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. 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	Sep. 30, 2015
Scenario, Forecast [Member]	'
Derivative [Line Items]	'
Estimated loss expected to be reclassified to earnings within the next twelve months	$2

FAIR_VALUE_MEASUREMENTS_AND_DE4

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	($6)	($1)	($4)	($2)

FAIR_VALUE_MEASUREMENTS_AND_DE5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Sep. 30, 2014	Dec. 31, 2013
	GWh	GWh
Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	842	779
Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	20,595,000,000	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 $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'	'
Derivative Assets	$0	$1
Derivative Liability	-4	-3
Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'	'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'	'
Derivative Assets	0	0
Derivative Liability	-3	-3
Valuation Technique Option Model [Member] | Options Held [Member]	'	'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'	'
Derivative Assets	0	1
Derivative Liability	($1)	$0
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'	'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'	'
Market price per MWh	27.5	27
Minimum [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'	'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'	'
Market price per MMbtu	3.67	3.88
Gas volatility	24.88%	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	43.5	48.25
Maximum [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'	'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'	'
Market price per MMbtu	4.24	4.32
Gas volatility	40.62%	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		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'	'
Beginning balance	$0	($1)	($2)	$0
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	-4	-1	-3	-2
Settlements	0	0	1	0
Ending balance	-4	-2	-4	-2
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	($2)	$0	($2)	($1)

FAIR_VALUE_MEASUREMENTS_AND_DE8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $)	Sep. 30, 2014
Derivative [Line Items]	'
FV of derivative instruments in net liability position with credit risk related features	$17,000,000
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	$17,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE9

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Liabilities:	'	'
Long-Term Debt	$1,372,369,000	$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	36,000,000
Fair Value [Member] | Level 2 [Member]	'	'
Liabilities:	'	'
Long-Term Debt	1,444,000,000	1,214,000,000
Fair Value [Member] | Level 3 [Member]	'	'
Assets:	'	'
Investment in Lease Equity	$26,000,000	$25,000,000

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'	'	'	'	'
Federal Income Tax Expense at Statutory Rate	'	$22,000,000	$36,000,000	$49,000,000	$48,000,000
State Income Tax Expense, Net of Federal Deduction	'	3,000,000	5,000,000	6,000,000	6,000,000
Federal/State Tax Credits	'	-2,000,000	-1,000,000	-4,000,000	-2,000,000
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	-11,000,000	'	'	0	-11,000,000
Other	'	1,000,000	-1,000,000	1,000,000	1,000,000
Income Tax Expense	'	$23,576,000	$38,828,000	$51,656,000	$41,737,000

RECLASSIFICATIONS_FROM_ACCUMUL2

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT Reclassifications From Accumulated Other Comprehensive Income By Component) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Interest Expense Long-Term Debt	$15,579	$13,848	$45,326	$42,412
Interest Expense Capital Leases	1,202	6,323	9,048	18,821
Purchased Energy	49,902	42,477	125,423	89,815
Other Nonoperating Expense	-7,170	-2,776	-11,979	-7,493
Income Tax Benefit	-23,576	-38,828	-51,656	-41,737
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	-674	-885	-1,914	-2,078
Other Comprehensive Income (Loss), Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service (Cost) Credit, Net of Tax	25	68	74	205
Total Reclassification from Other Comprehensive Income for the Period	-699	-953	-1,988	-2,283
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Income Tax Benefit	546	579	1,238	1,360
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | Interest Rate Swaps - Debt	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Interest Expense Long-Term Debt	-291	-296	-882	-871
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | Interest Rate Swaps - Capital Leases	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Interest Expense Capital Leases	-451	-612	-1,649	-1,820
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | Commodity Contracts	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Purchased Energy	-478	-556	-621	-747
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amortization, Net of Taxes	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Nonoperating Expense	-40	-110	-119	-332
Income Tax Benefit	$15	$42	$45	$127