Tucson Electric Power 10-Q 5 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	4-May-15
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	100122
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		32,139,434

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Utility Plant
Plant in Service	$5,225,923	$5,175,148
Utility Plant Under Capital Leases	436,199	667,157
Construction Work in Progress	173,889	109,070
Total Utility Plant	5,836,011	5,951,375
Less Accumulated Depreciation and Amortization	-2,091,266	-2,052,216
Less Accumulated Amortization of Capital Lease Assets	-286,693	-473,969
Total Utility Plant—Net	3,458,052	3,425,190
Investments and Other Property	38,428	37,599
Current Assets
Cash and Cash Equivalents	65,348	74,170
Accounts Receivable—Customer	72,702	80,713
Accounts Receivable—Other	15,498	12,808
Unbilled Accounts Receivable	32,069	36,804
Allowance for Doubtful Accounts-Customer	-4,776	-4,885
Allowance for Doubtful Accounts-Other	-5,521	0
Accounts Receivable—Due from Affiliates	4,617	5,382
Materials and Supplies	89,043	86,750
Deferred Income Taxes—Current	98,633	102,006
Fuel Inventory	33,758	36,368
Regulatory Assets—Current	79,380	69,383
Derivative Instruments	248	1,633
Other	25,557	22,848
Total Current Assets	506,556	523,980
Regulatory and Other Assets
Regulatory Assets—Noncurrent	238,018	223,192
Derivative Instruments	520	300
Other Assets	21,341	22,161
Total Regulatory and Other Assets	259,879	245,653
Total Assets	4,262,915	4,232,422
Capitalization
Common Stock Equity	1,225,282	1,215,779
Capital Lease Obligations	59,958	69,438
Long-Term Debt	1,541,486	1,372,414
Total Capitalization	2,826,726	2,657,631
Current Liabilities
Current Obligations Under Capital Leases	131,428	173,822
Borrowings Under Revolving Credit Facilities	0	85,000
Accounts Payable—Trade	93,682	110,480
Accounts Payable—Due to Affiliates	4,200	2,933
Accrued Taxes Other than Income Taxes	47,482	36,110
Accrued Employee Expenses	20,766	15,679
Regulatory Liabilities—Current	33,308	38,847
Accrued Interest	16,190	21,021
Customer Deposits	20,047	20,339
Derivative Instruments	22,016	18,874
Other	11,168	9,673
Total Current Liabilities	400,287	532,778
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	492,662	491,546
Regulatory Liabilities—Noncurrent	313,062	321,186
Pension and Other Postretirement Benefits	138,585	138,319
Derivative Instruments	7,476	6,288
Other	84,117	84,674
Total Deferred Credits and Other Liabilities	1,035,902	1,042,013
Commitments, Contingencies & Environmental Matters (Note 5)
Total Capitalization and Other Liabilities	$4,262,915	$4,232,422

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating Revenues
Electric Retail Sales	$201,622	$186,015
Electric Wholesale Sales	41,462	42,084
Other Revenues	30,308	27,414
Total Operating Revenues	273,392	255,513
Operating Expenses
Fuel	70,569	67,630
Purchased Power	30,522	22,615
Transmission and Other PPFAC Recoverable Costs	4,707	3,909
Increase (Decrease) to Reflect PPFAC Recovery Treatment	3,249	-1,730
Total Fuel and Purchased Energy	109,047	92,424
Operations and Maintenance	82,645	81,345
Depreciation	34,733	30,811
Amortization	5,562	7,099
Taxes Other Than Income Taxes	13,212	11,835
Total Operating Expenses	245,199	223,514
Operating Income	28,193	31,999
Other Income (Deductions)
Interest Income	29	9
Other Income	622	1,912
Other Expense	-462	-2,115
Appreciation (Depreciation) in Fair Value of Investments	780	255
Total Other Income (Deductions)	969	61
Interest Expense
Long-Term Debt	14,410	14,240
Capital Leases	1,004	3,921
Other Interest Expense	434	313
Interest Capitalized	-454	-924
Total Interest Expense	15,394	17,550
Income Before Income Taxes	13,768	14,510
Income Tax Expense	4,339	5,338
Net Income	$9,429	$9,172

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Net Income	$9,429	$9,172
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(12) and $(346)	14	481
Supplemental Executive Retirement Plan (SERP) Net Loss and Prior Service Cost Amortization, net of income tax (expense) benefit of $(37) and $(15)	60	24
Total Other Comprehensive Income (Loss), Net of Taxes	74	505
Total Comprehensive Income	$9,503	$9,677

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Income Tax (Expense) Benefit, Net Changes in Fair Value of Cash Flow Hedges	($12)	($346)
Income Tax (Expense) Benefit, SERP Amortization	($37)	($15)

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Cash Flows [Abstract]
Net Income	$9,429	$9,172
Cash Flows from Operating Activities
Depreciation	34,733	30,811
Amortization Expense	5,562	7,099
Amortization of Deferred Debt-Related Costs included in Interest Expense	716	635
Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue	5,521	0
Use of Renewable Energy Credits for Compliance	7,210	4,844
Deferred Income Taxes	4,339	5,337
Pension and Retiree Expense	4,647	3,412
Pension and Retiree Funding	-2,624	-1,657
Share-Based Compensation Expense	656	792
Allowance for Equity Funds Used During Construction	-343	-1,721
LFCR and DSM Revenues	-5,461	-6,226
Increase (Decrease) to Reflect PPFAC Recovery Treatment	3,249	-1,730
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately[Abstract]
Accounts Receivable	9,947	16,274
Materials and Fuel Inventory	-4,239	-3,182
Accounts Payable	-12,046	-3,425
Interest Accrued	-2,559	-3,260
Taxes Other Than Income Taxes	11,372	9,948
Other	-2,621	-1,809
Net Cash Flows – Operating Activities	67,488	65,314
Cash Flows from Investing Activities
Capital Expenditures	-99,291	-72,570
Purchase of Intangibles—Renewable Energy Credits	-6,325	-5,431
Purchase of Springerville Unit 1 Lease Assets	-45,753	0
CIAC	959	5,746
Other, net	0	1,664
Net Cash Flows—Investing Activities	-150,410	-70,591
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	15,000	105,000
Repayments of Borrowings Under Revolving Credit Facility	-100,000	-105,000
Proceeds from Borrowings Under Term Loan	130,000	0
Repayments of Borrowings Under Term Loan	-130,000	0
Proceeds from Issuance of Long-Term Debt	299,019	149,168
Repayments of Long-Term Debt	-130,000	0
Payments of Capital Lease Obligations	-8,394	-79,737
Payment of Debt Issue/Retirement Costs	-2,372	-1,471
Other, net	847	3
Net Cash Flows—Financing Activities	74,100	67,963
Net Increase (Decrease) in Cash and Cash Equivalents	-8,822	62,686
Cash and Cash Equivalents, Beginning of Year	74,170	25,335
Cash and Cash Equivalents, End of Period	$65,348	$88,021

CONDENSED_CONSOLIDATED_STATEME4

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY (USD $)	Total	Common Stock [Member]	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
In Thousands, unless otherwise specified	USD ($)		USD ($)	USD ($)	USD ($)	USD ($)
Balances at Dec. 31, 2014	$1,215,779		$1,116,539	($6,357)	$111,523	($5,926)
Common Shares at Dec. 31, 2014		32,139
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	9,429				9,429
Other Comprehensive Income, net of tax	74					74
Balances at Mar. 31, 2015	$1,225,282		$1,116,539	($6,357)	$120,952	($5,852)
Common Shares at Mar. 31, 2015		32,139

NATURE_OF_OPERATIONS_AND_FINAN

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	3 Months Ended
	Mar. 31, 2015
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 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis), which is a leader in the North American electric and gas utility business.
	BASIS OF PRESENTATION
	We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP), including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. See Note 2. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the condensed consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the condensed consolidated statements of income. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2014 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.
	In 2014, following the acquisition of UNS Energy by Fortis, TEP 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.
	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2015, we adopted accounting guidance that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows.

REGULATORY_MATTERS

REGULATORY MATTERS	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS
	The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (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
	The ACC adjusts TEP's Purchased Power and Fuel Adjustment Clause (PPFAC) rate annually each April 1 for the subsequent 12-month period. The ACC approved rates of 0.50 cents per Kilowatt-hours (kWh) for the three months ended March 31, 2015 and 0.14 cents per kWh for the three months ended March 31, 2014. In March 2015, the ACC approved a PPFAC rate for TEP of 0.68 cents per kWh for the period April 2015 through March 2016.
	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 March 31, 2015, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining incremental 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, including related operating expenses, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP recognized ECA revenues of less than $0.5 million in the first three months of 2015.
	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 an annual performance incentive. In the first three months of 2015, TEP recorded an annual DSM performance incentive of $3 million related to savings realized in 2014 that is included in the Electric Retail Sales line item in the accompanying condensed consolidated statements of income.
	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. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of the company's total retail revenues.
	TEP recorded a regulatory asset and recognized LFCR revenues of $3 million in the first three months of 2015 and $5 million in the first three months of 2014. LFCR revenues are included in the Electric Retail Sales in the accompanying condensed consolidated statements of income.
	The ACC approved recovery of $5 million through the LFCR recovery mechanism effective August 2014 for the subsequent 12-month period.
	REGULATORY ASSETS
	TEP's total regulatory assets, including current and noncurrent assets, increased $25 million at March 31, 2015 from December 31, 2014, primarily due to the reclassification of unamortized leasehold improvement costs upon expiration of the Springerville Unit 1 capital lease in January 2015 that relate to third-party ownership interests. These leasehold improvements, previously recorded in Plant in Service, represent investments TEP made through the end of the lease term to ensure that the Springerville facilities continued providing safe, reliable service to TEP's customers. In its 2013 Rate Case, TEP requested and received ACC authorization to use a 10-year amortization period for leasehold improvements at Springerville Unit 1. TEP owns a 49.5% undivided interest in Springerville Unit 1.

RELATED_PARTY_TRANSACTIONS_REL

RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS
	TEP engages in various transactions with Fortis, Inc., UNS Energy and its affiliated subsidiaries including Unisource Energy Services, Inc., 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.
	At March 31, 2015 and December 31, 2014, our balance sheets include the following intercompany balances:
		Balances at
		31-Mar-15		31-Dec-14
		Millions of Dollars
	Receivables from Related Parties
	UNS Electric	$	4	$	4
	UNS Gas	1		1
	Total Due from Related Parties	$	5	$	5
	Payables to Related Parties
	SES	$	3	$	2
	UNS Energy	1		—
	UNS Electric	—		1
	Total Due to Related Parties	$	4	$	3
	The following table summarizes related party transactions:
		Three Months Ended March 31,
		2015		2014
		Millions of Dollars
	Wholesale Sales - TEP to UNS Electric (1)	$	2	$	—
	Control Area Services - TEP to UNS Electric (2)	—		1
	Common Costs - TEP to UNS Energy Affiliates (3)	3		3
	Supplemental Workforce - SES to TEP (4)	4		4
	Corporate Services - UNS Energy to TEP (5)	1		1
	(1)	TEP sells power to UNS Electric at prevailing market prices.
	(2)	TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement.
	(3)	Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
	(4)	SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable.
	(5)	Corporate costs at UNS Energy, such as Fortis management fees, legal fees, and audit fees, are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 81% of UNS Energy's allocated costs. For the three months ended March 31, 2015 these costs included approximately $1 million in Fortis management fees and for the three months ended March 31, 2014 these costs included approximately $1 million in merger related costs.
	Share-Based Compensation Expense
	In January 2015, UNS Energy established a new share-based compensation plan, referred to as the 2015 Share Unit Plan (the Plan), to promote greater alignment of interests between the senior management of UNS Energy and its subsidiaries and the shareholders of Fortis. TEP recognized less than $1 million of share-based compensation expense under the Plan for the three months ended March 31, 2015. For the three months ended March 31, 2014, TEP recognized less than $1 million of expense under UNS Energy's prior share-based compensation plan.

DEBT_AND_CAPITAL_LEASE_OBLIGAT

DEBT AND CAPITAL LEASE OBLIGATIONS	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [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 2014 Annual Report on Form 10-K.
	CAPITAL LEASE OBLIGATIONS
	Springerville Unit 1 Capital Lease Purchase
	In January 2015, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value. With the completion of the lease option purchase, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses. See Note 5.
	Springerville Coal Handling Facilities Lease Purchase Commitment
	In April 2015, upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, bringing its total ownership of the assets to 100%. With the completion of this purchase, Salt River Project Agricultural Improvement and Power District (SRP) is obligated to purchase a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State Generation and Transmission Association, Inc. (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. TEP expects SRP to complete its purchase commitment in the second quarter 2015. Tri-State has until April 2016 to elect an option. At March 31, 2015, no amounts have been recorded on TEP's balance sheet for commitments from either SRP or Tri-State.
	UNSECURED BOND ISSUANCES AND REDEMPTIONS
	In January 2015, amounts borrowed under the 2014 Credit Agreement term loan portion were used to purchase $130 million aggregate principal amount of unsecured Industrial Development Revenue Bonds (IDRBs) issued in June 2008 by the Industrial Development Authority of Pima County for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.75% and mature in September 2029. TEP did not cancel the purchased bonds and had not remarketed them as of March 31, 2015; therefore, they are not reflected as debt on the balance sheet.
	In February 2015, TEP issued and sold $300 million aggregate principal amount of its senior unsecured notes bearing interest at the fixed rate of 3.05% and maturing March 15, 2025. TEP may redeem the notes prior to December 15, 2024, with a make-whole premium plus accrued interest. On or after December 15, 2024, TEP may redeem the notes at par plus accrued interest. Interest on the notes will be payable semi-annually on each March 15 and September 15, beginning September 15, 2015, and at maturity.
	In March 2015, TEP used the net proceeds from the sale to repay $215 million of revolving and term loans under its 2014 Credit Agreement and 2010 Credit Agreement. See Credit Agreements below. In April 2015, TEP used the remaining amount to pay a portion of the purchase price for its ownership interests in the Springerville Coal Handling Facilities.
	CREDIT AGREEMENTS
	2014 Credit Agreement
	In March 2015, net proceeds from the sale of senior unsecured notes were used to repay the 2014 Credit Agreement's $70 million outstanding revolver borrowings and $130 million outstanding term loan. The $130 million term loan portion cannot be reborrowed per the terms of the agreement. See Unsecured Bond Issuances and Redemptions above.
	As of March 31, 2015, there was $70 million available under the revolving credit facility of the 2014 Credit Agreement. As of May 4, 2015, TEP had nothing available under the 2014 Credit Agreement revolving credit facility.
	2010 Credit Agreement
	Interest rates and fees under the 2010 Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. With Moody's Investors Service, Inc. (Moody's) increase to TEP's credit rating in February 2015, the interest rate currently in effect on borrowings decreased to LIBOR plus 1.00% for Eurodollar loans or Alternate Base Rate plus 0.00% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million Letter of Credit (LOC) facility decreased to 1.00%.
	In March 2015, net proceeds from the sale of senior unsecured notes were used to repay $15 million of revolver borrowings outstanding. See Unsecured Bond Issuances and Redemptions above.
	As of March 31, 2015, there was $200 million available under the revolving credit facility of the 2010 Credit Agreement. As of May 4, 2015, TEP had $142 million available under the 2010 Credit Agreement revolving credit facility.
	2010 TEP REIMBURSEMENT AGREEMENT
	The 2010 TEP Reimbursement Agreement supports $37 million aggregate principal amount of variable rate tax-exempt bonds and includes fees payable on the aggregate outstanding amount. The rate currently in effect decreased to 0.75% per annum after credit rating upgrade in February 2015.
	COVENANT COMPLIANCE
	At March 31, 2015, we were in compliance with the terms of our loan and credit agreements.

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
	COMMITMENTS
	In addition to those reported in our 2014 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2015:
		2015		2016		2017		2018		2019		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	1	$	2	$	2	$	2	$	2	$	47	$	56
	Purchased Power	30		11		—		—		—		—		41
	Total Purchase Commitments	$	31	$	13	$	2	$	2	$	2	$	47	$	97
	CONTINGENCIES
	Navajo Generating Station Lease Extension
	Navajo Generating Station (Navajo) is located on a site that is leased from the Navajo Nation with an initial lease term through 2019. The Navajo Nation signed a lease amendment that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agree to the terms. To become effective, this lease amendment must be signed by all of the participants, approved by the Department of the Interior, and is subject to environmental reviews. TEP owns 7.5% of Navajo. In the first quarter of 2015, TEP recorded additional estimated lease expense of approximately $1 million with the expectation that the lease amendment will become effective. At March 31, 2015, TEP's balance sheet reflects a total liability related to the lease amendment of $3 million recorded in Deferred Credits and Other Liabilities—Other.
	Claims Related to Springerville Generating Station Unit 1
	On November 7, 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1, 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint. On March 23, 2015, the Third-Party Owners filed a request for rehearing in the FERC Action. On April 7, 2015, TEP filed an answer in response to the request for rehearing. The FERC has not yet ruled on the request for rehearing.
	On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners' instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action, and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses. On February 20, 2015, TEP filed a motion to dismiss in the New York Action that requested that the court dismiss various counts of the complaint. On March 20, 2015, the Third-Party Owners filed a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the Third-Party Owners instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that TEP has failed to pay the Third-Party Owners approximately $71 million in liquidated damages they allege they are owed (see following paragraph), that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired, that TEP has converted the Third-Party Owners’ water rights and that TEP has been unjustly enriched as a result, and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. On April 20, 2015, TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action.
	On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.
	On April 20, 2015, TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1. As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015.
	TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.
	Claims Related to San Juan Generating Station
	San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
	In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.
	In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United States District Court of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and San Juan. TEP cannot currently predict the outcome of this matter or the range of its potential impact.
	Claims Related to Four Corners Generating Station
	In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until June 1, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation. A final consent decree version is currently being circulated for signature by all of the parties.
	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. TEP cannot predict the final 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 $52 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability recorded was $23 million at March 31, 2015 and $22 million at December 31, 2014.
	Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
	TEP’s PPFAC allows us to pass through final reclamation costs, as a component of fuel cost, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
	Discontinued Transmission Project
	TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-Kilo-volt (kV) line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using the route, or a portion thereof, 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 March 31, 2015, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements for the San Juan, Navajo, Four Corners and Luna generating facilities expire in 2019 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.
	Coal Combustion Residuals Regulations
	In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. The additional requirements would apply to lateral expansion of those existing landfills or to any new landfill.
	Hazardous Air Pollutant Requirements
	In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics Standards (MATS) rules, additional emission control equipment would have been required by April 2015. However, 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 Springerville Units 1 & 2, with estimated costs split equally between the two units. In January 2015, TEP completed the purchase of 49.5% of Springerville Unit 1. With the completion of the purchase, Third Party Owners are 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 land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
	In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). Complying with 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. These BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.
	TEP's estimated costs involved in meeting these rules are:
	Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
		Millions of Dollars
	Capital Expenditures	$	28	$	37	$	44	$	12
	Annual O&M Expenses	1		1		2		6-May
	(1)	In August 2014, the EPA published a final Federal Implementation Plan (FIP) wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
	-2	In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million. Prior to the shutdown of any units at San Juan, PNM, the operator, must first obtain New Mexico Public Regulation Commission approval. At March 31, 2015, the net book value of TEP's share in San Juan Unit 2 was $109 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
	-3	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
	-4	In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS
	Net periodic benefit plan cost includes the following components:
		Pension Benefits						Other Retiree Benefits
		Three Months Ended March 31,
		2015			2014			2015		2014
		Millions of Dollars
	Service Cost	$	3		$	2		$	1	$	1
	Interest Cost	4			4			1		—
	Expected Return on Plan Assets	(6		)	(5		)	—		—
	Actuarial Loss Amortization	2			1			—		—
	Net Periodic Benefit Cost	$	3		$	2		$	2	$	1

FAIR_VALUE_MEASUREMENTS_AND_DE

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	3 Months Ended
	Mar. 31, 2015
Fair Value Measurements and Derivative Instruments Disclosure [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
		31-Mar-15
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	50			$	50			$	—			$	—			$	—		$	50
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	27				—				27				—				—			27
	Energy Contracts - Regulatory Recovery(3)	1				—				—				1				(1		)	—
	Total Assets	80				52				27				1				(1		)	79
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(25		)		—				(13		)		(12		)		1			(24		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(4		)		—				(4		)		—				—			(4		)
	Total Liabilities	(30		)		—				(17		)		(13		)		1			(29		)
	Net Total Assets (Liabilities)	$	50			$	52			$	10			$	(12	)		$	—		$	50
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	15			$	15			$	—			$	—			$	—		$	15
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	26				—				26				—				—			26
	Energy Contracts - Regulatory Recovery(3)	2				—				—				2				(2		)	—
	Total Assets	45				17				26				2				(2		)	43
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(18		)		—				(9		)		(9		)		1			(17		)
	Energy Contracts - No Regulatory Recovery(3)	(1		)		—				—				(1		)		1			—
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(5		)		—				(5		)		—				—			(5		)
	Total Liabilities	(25		)		—				(14		)		(11		)		2			(23		)
	Net Total Assets (Liabilities)	$	20			$	17			$	12			$	(9	)		$	—		$	20
	(1)	Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
	(2)	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
	(3)	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014, a power sale option. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
	(4)	An Interest Rate Swap valued using an income valuation approach, based on the 6-month London Interbank Offered Rate (LIBOR) is 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.
	The December 31, 2014 valuation of our power sale option was a function of observable market variables, regional power and gas prices, as well as the ratio between the two, which represents the prevailing market heat rate.
	We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no transfers between levels in the periods presented.
	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 agreement expires January 2020. The realized loss recorded to Capital Lease Interest Expense was less than $0.5 million for the three months ended March 31, 2015 and less than $1 million for the three months ended March 31, 2014. The realized loss recorded to Long-Term Debt Interest Expense for three months ended March 31, 2014 was less than $0.5 million. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statements of other comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million.
	Energy Contracts - Regulatory Recovery
	We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following table:
			Three Months Ended March 31,
			2015				2014
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities		$	(6	)		$	1
	Energy Contracts - No Regulatory Recovery
	Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For these contracts that qualify as derivatives, we record unrealized gains and losses in the income statement, unless and until a normal purchase or normal sale election is made. In the first quarter of 2015, TEP made a normal sale election for a three-year sales option contract entered into in December 2014.
	Derivative Volumes
	At March 31, 2015, we have energy contracts that will settle through the first quarter of 2018. The volumes associated with our energy contracts were as follows:
			March 31, 2015			December 31, 2014
	Power Contracts GWh		1,008			2,604
Gas Contracts GBtu		24,027			19,932
Level 3 Fair Value Measurements
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
			Fair Value at
	Valuation		31-Mar-15										Range of
	Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Power Contracts	Market approach		$	1			$	(8	)		Market price per MWh		$	23.8			$	37.7
Gas Option Contracts	Option model		—				(5		)		Market price per MMbtu		$	2.34			$	3.22
											Gas volatility		24.15		%		39.91		%
Level 3 Energy Contracts			$	1			$	(13	)
			Fair Value at
	Valuation		31-Dec-14										Range of
	Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Power Contracts	Market approach		$	1			$	(6	)		Market price per MWh		$	22.35			$	39.05
Power Sale Option	Market approach		1				(1		)		Market price per MWh		$	27.75			$	44.94
											Market price per MMbtu		$	2.88			$	4.02
Gas Option Contracts	Option model		—				(4		)		Market price per MMbtu		$	2.72			$	3.26
											Gas volatility		30.8		%		53.29		%
Level 3 Energy Contracts			$	2			$	(11	)
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, that 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 March 31,
		2015				2014
		Millions of Dollars
Balances at December 31		$	(9	)		$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(2		)		(1		)
Settlements		(1		)		1
Balances at March 31		$	(12	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(3	)		$	—
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.
We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.
Material adverse changes could trigger credit risk-related contingent features. At March 31, 2015, 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 $27 million, compared with $21 million at December 31, 2014. At March 31, 2015, TEP had no cash collateral posted and less than $0.5 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $27 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 Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
			31-Mar-15								31-Dec-14
	Fair Value		Carrying				Fair				Carrying				Fair
	Hierarchy		Value				Value				Value				Value
			Millions of Dollars
Long-Term Debt	Level 2		$	1,541			$	1,642			$	1,372			$	1,457

RECENTLY_ISSUED_ACCOUNTING_PRO

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
	In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. The revenue standard requires entities to apply the guidance retrospectively or recognize the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. On April 1, 2015, the FASB proposed to defer the effective date of the revenue recognition standard by one year. Based on the proposed effective date, we will be required to adopt the new guidance for annual and interim periods beginning January 1, 2018; early adoption is permitted for annual and interim periods beginning January 1, 2017. We are in the process of identifying contracts with customers and performance obligations in contracts.
	In June 2014, the FASB issued guidance that requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.
	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.
	In January 2015, the FASB issued an accounting standards update that removes the concept of extraordinary items from U.S. GAAP. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. TEP does not expect the adoption of this guidance to impact its results of operations or disclosures.
	In February 2015, the FASB issued guidance that amends the current consolidation guidance; the amendment affects both the variable interest entity and voting interest entity consolidation models. This standard is effective beginning January 1, 2016; early adoption is permitted. We are evaluating the impact to our financial statements and disclosures.
	In April 2015, the FASB issued guidance which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The amendment is effective for periods beginning January 1, 2016 and will be applied retrospectively; early adoption is permitted. The adoption of this standard is expected to result in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on our balance sheet. TEP’s deferred debt issuance costs associated with long-term debt outstanding totaled $12 million at March 31, 2015 and $11 million at December 31, 2014, of which approximately $1 million is classified as current at each date.
	In April 2015, the FASB issued guidance that will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement either as a software license or a service contract. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.

NATURE_OF_OPERATIONS_AND_FINAN1

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 2015
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), including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. See Note 2. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the condensed consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the condensed consolidated statements of income. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2014 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.
	In 2014, following the acquisition of UNS Energy by Fortis, TEP 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.
Recently Adopted Accounting Pronouncements	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2015, we adopted accounting guidance that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows.

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Table)	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	At March 31, 2015 and December 31, 2014, our balance sheets include the following intercompany balances:
		Balances at
		31-Mar-15		31-Dec-14
		Millions of Dollars
	Receivables from Related Parties
	UNS Electric	$	4	$	4
	UNS Gas	1		1
	Total Due from Related Parties	$	5	$	5
	Payables to Related Parties
	SES	$	3	$	2
	UNS Energy	1		—
	UNS Electric	—		1
	Total Due to Related Parties	$	4	$	3
	The following table summarizes related party transactions:
		Three Months Ended March 31,
		2015		2014
		Millions of Dollars
	Wholesale Sales - TEP to UNS Electric (1)	$	2	$	—
	Control Area Services - TEP to UNS Electric (2)	—		1
	Common Costs - TEP to UNS Energy Affiliates (3)	3		3
	Supplemental Workforce - SES to TEP (4)	4		4
	Corporate Services - UNS Energy to TEP (5)	1		1
	(1)	TEP sells power to UNS Electric at prevailing market prices.
	(2)	TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement.
	(3)	Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
	(4)	SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable.
	(5)	Corporate costs at UNS Energy, such as Fortis management fees, legal fees, and audit fees, are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 81% of UNS Energy's allocated costs. For the three months ended March 31, 2015 these costs included approximately $1 million in Fortis management fees and for the three months ended March 31, 2014 these costs included approximately $1 million in merger related costs.

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments	In addition to those reported in our 2014 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2015:
		2015		2016		2017		2018		2019		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	1	$	2	$	2	$	2	$	2	$	47	$	56
	Purchased Power	30		11		—		—		—		—		41
	Total Purchase Commitments	$	31	$	13	$	2	$	2	$	2	$	47	$	97
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 Springerville Units 1 & 2, with estimated costs split equally between the two units. In January 2015, TEP completed the purchase of 49.5% of Springerville Unit 1. With the completion of the purchase, Third Party Owners are 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's estimated costs involved in meeting these rules are:
	Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
		Millions of Dollars
	Capital Expenditures	$	28	$	37	$	44	$	12
	Annual O&M Expenses	1		1		2		6-May
	(1)	In August 2014, the EPA published a final Federal Implementation Plan (FIP) wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
	-2	In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million. Prior to the shutdown of any units at San Juan, PNM, the operator, must first obtain New Mexico Public Regulation Commission approval. At March 31, 2015, the net book value of TEP's share in San Juan Unit 2 was $109 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
	-3	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
	-4	In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Cost	Net periodic benefit plan cost includes the following components:
		Pension Benefits						Other Retiree Benefits
		Three Months Ended March 31,
		2015			2014			2015		2014
		Millions of Dollars
	Service Cost	$	3		$	2		$	1	$	1
	Interest Cost	4			4			1		—
	Expected Return on Plan Assets	(6		)	(5		)	—		—
	Actuarial Loss Amortization	2			1			—		—
	Net Periodic Benefit Cost	$	3		$	2		$	2	$	1

FAIR_VALUE_MEASUREMENTS_AND_DE1

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Measurements and Derivative Instruments Disclosure [Abstract]
Schedule of Fair Value Measurements of Financial Assets and Liabilities	The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Mar-15
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	50			$	50			$	—			$	—			$	—		$	50
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	27				—				27				—				—			27
	Energy Contracts - Regulatory Recovery(3)	1				—				—				1				(1		)	—
	Total Assets	80				52				27				1				(1		)	79
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(25		)		—				(13		)		(12		)		1			(24		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(4		)		—				(4		)		—				—			(4		)
	Total Liabilities	(30		)		—				(17		)		(13		)		1			(29		)
	Net Total Assets (Liabilities)	$	50			$	52			$	10			$	(12	)		$	—		$	50
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	15			$	15			$	—			$	—			$	—		$	15
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	26				—				26				—				—			26
	Energy Contracts - Regulatory Recovery(3)	2				—				—				2				(2		)	—
	Total Assets	45				17				26				2				(2		)	43
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(18		)		—				(9		)		(9		)		1			(17		)
	Energy Contracts - No Regulatory Recovery(3)	(1		)		—				—				(1		)		1			—
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(5		)		—				(5		)		—				—			(5		)
	Total Liabilities	(25		)		—				(14		)		(11		)		2			(23		)
	Net Total Assets (Liabilities)	$	20			$	17			$	12			$	(9	)		$	—		$	20
	(1)	Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
	(2)	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
	(3)	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014, a power sale option. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
	(4)	An Interest Rate Swap valued using an income valuation approach, based on the 6-month London Interbank Offered Rate (LIBOR) is 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	Energy Contracts - Regulatory Recovery
	We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following table:
			Three Months Ended March 31,
			2015				2014
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities		$	(6	)		$	1
Derivative Volumes	Derivative Volumes
	At March 31, 2015, we have energy contracts that will settle through the first quarter of 2018. The volumes associated with our energy contracts were as follows:
			March 31, 2015			December 31, 2014
	Power Contracts GWh		1,008			2,604
	Gas Contracts GBtu		24,027			19,932
Quantitative Information Regarding Unobservable Inputs	The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
				Fair Value at
		Valuation		31-Mar-15										Range of
		Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Power Contracts	Market approach		$	1			$	(8	)		Market price per MWh		$	23.8			$	37.7
	Gas Option Contracts	Option model		—				(5		)		Market price per MMbtu		$	2.34			$	3.22
												Gas volatility		24.15		%		39.91		%
	Level 3 Energy Contracts			$	1			$	(13	)
				Fair Value at
		Valuation		31-Dec-14										Range of
		Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Power Contracts	Market approach		$	1			$	(6	)		Market price per MWh		$	22.35			$	39.05
	Power Sale Option	Market approach		1				(1		)		Market price per MWh		$	27.75			$	44.94
												Market price per MMbtu		$	2.88			$	4.02
	Gas Option Contracts	Option model		—				(4		)		Market price per MMbtu		$	2.72			$	3.26
												Gas volatility		30.8		%		53.29		%
	Level 3 Energy Contracts			$	2			$	(11	)
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 March 31,
			2015				2014
			Millions of Dollars
	Balances at December 31		$	(9	)		$	(2	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments		(2		)		(1		)
	Settlements		(1		)		1
	Balances at March 31		$	(12	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period		$	(3	)		$	—
Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments	The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
				31-Mar-15								31-Dec-14
		Fair Value		Carrying				Fair				Carrying				Fair
		Hierarchy		Value				Value				Value				Value
				Millions of Dollars
	Long-Term Debt	Level 2		$	1,541			$	1,642			$	1,372			$	1,457

NATURE_OF_OPERATIONS_AND_FINAN2

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION - Nature of Operations (Details)	3 Months Ended
	Mar. 31, 2015
	sqmi
	customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Entity Number Of Customers	417,000
Area In Which Subsidiary Generates Transmits And Distributes Electricity To Retail Electric Customers	1,155

REGULATORY_MATTERS_COST_RECOVE

REGULATORY MATTERS COST RECOVERY MECHANISMS (Details) (USD $)	0 Months Ended	3 Months Ended		1 Months Ended	43 Months Ended
In Millions, unless otherwise specified	1-May-14	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2015
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Purchased Power And Fuel Adjustment Clause Rate		0.005	0.0014
Mine Fire Cost Deferral		$10		$10	$10
Environmental Compliance Adjustor Rate Effective On May 1 2014	0.000049
Revenue Recognized Under Environmental Compliance Adjustor Less Than		0.5
Energy Efficiency Performance Incentive		3
Cap on increase in lost fixed cost recovery rate		1.00%
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism		3	5
Lost Fixed Cost Recovery Approved		5
Effective April 2015 Through March 2016 [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Purchased Power And Fuel Adjustment Clause Rate				0.00682
Fire [Member]
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Insurance Proceeds Received to Date					$8

REGULATORY_MATTERS_REGULATORY_

REGULATORY MATTERS REGULATORY ASSETS (Details) (Springerville Unit One [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Jan. 31, 2015
Jointly Owned Utility Plant Interests [Line Items]
Increase (Decrease) in Other Regulatory Assets	$25
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Amortization Period	10 years
Completion of Purchase of Equity Interest [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		49.50%

Recovered_Sheet1

RELATED PARTY TRANSACTIONS Related Party Transactions Other Than Share-Based Compensation (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	$5		$5
Payable to Related Parties	4		3
Intercompany Allocation Parent to Subsidiary	81.00%
Management fee	1
Merger Related Costs		1
Tucson Electric Power Company To Uns Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Wholesale Sales	2	0
Control Area Services	0	1
TEP to UNS Energy Affiliates [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Common Costs	3	3
Southwest Energy Solutions, Inc. to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Supplemental Workforce	4	4
UNS Energy to TEP [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services	1	1
UNS Electric [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	4		4
Payable to Related Parties	0		1
Uns Gas [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivable from Related Parties	1		1
Uns Energy Corporation [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payable to Related Parties	1		0
Southwest Energy Solutions, Inc. [Member]
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payable to Related Parties	$3		$2

RELATED_PARTY_TRANSACTIONS_Sha

RELATED PARTY TRANSACTIONS Share-Based Compensation Expense (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Related Party Transactions [Abstract]
Allocated Share-based Compensation Expense Less Than	$1	$1

DEBT_AND_CAPITAL_LEASE_OBLIGAT1

DEBT AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Details) (USD $)	1 Months Ended
	Apr. 30, 2015	Jan. 31, 2015	Mar. 31, 2015	Jun. 30, 2015	Apr. 30, 2016
		MW
Springerville Unit One [Member] | Additional Purchase of Equity Interest [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		24.80%
Lease Arrangement, Fair Market Value Purchase Price		$46,000,000
Generating Capacity Purchased, in MWs		96
Springerville Unit One [Member] | Completion of Purchase of Equity Interest [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		49.50%
Generating Capacity Purchased, in MWs		192
Springerville Coal Handling Facilities Lease [Member] | SRP [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Recorded Amounts of Third Party Commitments			0
Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Recorded Amounts of Third Party Commitments			0
Subsequent Event [Member] | Springerville Coal Handling Facilities Lease [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	100.00%
Jointly Owned Utility Plant Proportionate Ownership Share, Purchased	86.70%
Fixed price to acquire leased interest in facilities	120,000,000
Subsequent Event [Member] | Springerville Coal Handling Facilities Lease [Member] | SRP [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Sales Price of Leased Interest In Facilities				24,000,000
Subsequent Event [Member] | Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member]
Capital Lease Asset Purchase Commitment [Line Items]
Sales Price of Leased Interest In Facilities					$24,000,000

DEBT_AND_CAPITAL_LEASE_OBLIGAT2

DEBT AND CAPITAL LEASE OBLIGATIONS (Debt) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Feb. 27, 2015	Apr. 23, 2015	4-May-15
Short-term Debt [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$215,000,000
TEP 2014 Credit Agreement [Member] | Domestic Line of Credit [Member] | Domestic Line of Credit [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	70,000,000
TEP 2014 Credit Agreement [Member] | Loans Payable [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	130,000,000
TEP 2010 Credit Agreement [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Interest Rate In Addition To Alternate Base Rate For Alternate Base Rate Loans	0.00%
TEP 2010 Reimbursement Agreement [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases	37,000,000
Line of Credit Facility, Interest Rate at Period End	0.75%
Unsecured Debt [Member] | Unsecured Debts, 5.75%, due September 2029 [Member]
Debt Instrument [Line Items]
Repurchased Debt Amount	130,000,000
Fixed interest rate of long-term debt	5.75%
Debt Instrument, Maturity Date	1-Sep-29
Unsecured Debt [Member] | Unsecured Debts, 3.05%, due March 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		300,000,000
Fixed interest rate of long-term debt		3.05%
Debt Instrument, Maturity Date	15-Mar-25
Debt Instrument, Call Date, Latest	15-Dec-24
Debt Instrument, Frequency of Periodic Payment	semi-annually
Variable Rate Demand Obligation [Member] | Secured Debts, Variable Weekly 2010 Pollution Control Coconino Series A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face amount	37,000,000
Revolving Credit Facility [Member] | TEP 2014 Credit Agreement [Member] | Domestic Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	70,000,000
Revolving Credit Facility [Member] | TEP 2010 Credit Agreement [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	200,000,000
Revolving Credit Facility [Member] | TEP 2010 Credit Agreement [Member] | Revolving Credit Facility [Member] | Domestic Line of Credit [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	15,000,000
Letter of Credit [Member] | TEP 2010 Credit Agreement [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Letters of Credit Outstanding, Amount	82,000,000
Subsequent Event [Member] | Revolving Credit Facility [Member] | TEP 2014 Credit Agreement [Member] | Domestic Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			0
Subsequent Event [Member] | Revolving Credit Facility [Member] | TEP 2010 Credit Agreement [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				$142,000,000

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS COMMITMENTS (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	$31
2016	13
2017	2
2018	2
2019	2
Thereafter	47
Total	97
Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	1
2016	2
2017	2
2018	2
2019	2
Thereafter	47
Total	56
Purchased Power
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	30
2016	11
2017	0
2018	0
2019	0
Thereafter	0
Total	$41

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS CONTINGENCIES (Detail) (USD $)	1 Months Ended	3 Months Ended
	Dec. 31, 2012	Mar. 31, 2015	Dec. 31, 2014	4-May-15
Commitments And Contingencies [Line Items]
Allowance for Doubtful Other Receivables, Current		$5,521,000	$0
TEP's share of reclamation costs at expiration dates of the coal supply agreements		52,000,000
TEP's recorded obligations for final mine reclamation costs		23,000,000	22,000,000
Share of Defaulting Participants' Payment		0
San Juan [Member]
Commitments And Contingencies [Line Items]
Percentage Of Ownership In Generating Units		20.00%
Tucson to Nogales [Member]
Commitments And Contingencies [Line Items]
Transmission line from Tucson to Nogales in Milies		60
Transmission Line, in KV		345
Asset Impairment Charges	5,000,000
Regulatory Assets		5,000,000
Springerville Unit 1 Third Party Owner Allegation [Member]
Commitments And Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		71,000,000
Springerville Unit One [Member]
Commitments And Contingencies [Line Items]
Other Receivables, Gross, Current		6,000,000
Receivable for Capital		500,000
Springerville Unit One [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Amount paid by Spr Unit 1 Third Party Owners				0
Navajo [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		7.50%
Loss Contingency Accrual, Provision		1,000,000
Estimate of Possible Loss Contingency		3,000,000
San Juan [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		50.00%
San Juan [Member] | Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		5,000,000
San Juan [Member] | Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		1,000,000
Four Corner [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		7.00%
Accrual for Environmental Loss Contingency		1,000,000
Four Corner [Member] | Assessment for Coal Severance Tax, Coal Supplier [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		30,000,000
Four Corner [Member] | Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		$1,000,000

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS ENVIRONMENTAL MATTERS (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Jan. 31, 2015
Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	$44
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2
Sundt [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Monitoring Equipment, Less Than	1
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12
Jointly Owned Utility Plant, Net Ownership Amount	17
Sundt [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5
Sundt [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	6
Springerville Unit One [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	5
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Third-Party Participating in Ownership Interest	50.50%
TEP's Share (in Percentage) of Obligations for Environmental Costs	100.00%
Springerville Unit One [Member] | Completion of Purchase of Equity Interest [Member]
Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		49.50%
Navajo [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	1
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Jointly Owned Utility Plant, Proportionate Ownership Share	7.50%
Estimated Capital Expenditure for Selective Catalytic Reduction	28
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1
Better Than BART Agreement Year by which to Shut Down One Unit	2020
Better than BART Agreement, Year by which SCR Technology to be Installed	2030
Estimated Capital Expenditure Related to Installation of Baghouses	28
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses, Less Than	1
San Juan [Member]
Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Estimated Capital Expenditure for Selective Catalytic Reduction	37
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1
San Juan Unit One [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1
BalancedDraftUpgradePortionOfEstimatedCapitalExpenditureForSelectiveCatalyticReduction	25
San Juan Unit Two [Member]
Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant, Net Ownership Amount	$109

EMPLOYEE_BENEFIT_PLANS_Compone

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Pension Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	$3	$2
Interest Cost	4	4
Expected Return on Plan Assets	-6	-5
Amortization of Actuarial (Gain) Loss	2	1
Net Periodic Benefit Plan Cost	3	2
Other Retiree Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1
Interest Cost	1	0
Expected Return on Plan Assets	0	0
Amortization of Actuarial (Gain) Loss	0	0
Net Periodic Benefit Plan Cost	$2	$1

FAIR_VALUE_MEASUREMENTS_AND_DE2

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Assets
Cash Equivalent	$50	$15
Restricted Cash	2	2
Rabbi Trust Investments(2)	27	26
Total Assets	80	45
Liabilities
Liabilities	-30	-25
Net Total Assets (Liability)	50	20
Energy Related Derivative [Member]
Assets
Derivative Assets	1	2
Liabilities
Derivative Liability	-25	-18
Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability		-1
Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	-1	-1
Interest Rate Swap [Member]
Liabilities
Derivative Liability	-4	-5
Level 1 [Member]
Assets
Cash Equivalent	50	15
Restricted Cash	2	2
Rabbi Trust Investments(2)	0	0
Total Assets	52	17
Liabilities
Liabilities	0	0
Net Total Assets (Liability)	52	17
Level 1 [Member] | Energy Related Derivative [Member]
Assets
Derivative Assets	0	0
Liabilities
Derivative Liability	0	0
Level 1 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability		0
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	0
Level 1 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	0
Level 2 [Member]
Assets
Cash Equivalent	0	0
Restricted Cash	0	0
Rabbi Trust Investments(2)	27	26
Total Assets	27	26
Liabilities
Liabilities	-17	-14
Net Total Assets (Liability)	10	12
Level 2 [Member] | Energy Related Derivative [Member]
Assets
Derivative Assets	0	0
Liabilities
Derivative Liability	-13	-9
Level 2 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability		0
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	0
Level 2 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	-4	-5
Level 3 [Member]
Assets
Cash Equivalent	0	0
Restricted Cash	0	0
Rabbi Trust Investments(2)	0	0
Derivative Assets	1	2
Total Assets	1	2
Liabilities
Derivative Liability	-13	-11
Liabilities	-13	-11
Net Total Assets (Liability)	-12	-9
Level 3 [Member] | Energy Related Derivative [Member]
Assets
Derivative Assets	1	2
Liabilities
Derivative Liability	-12	-9
Level 3 [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability		-1
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	-1	-1
Level 3 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	0
Netting [Member]
Assets
Cash Equivalent	0	0
Restricted Cash	0	0
Rabbi Trust Investments(2)	0	0
Total Assets	-1	-2
Liabilities
Liabilities	1	2
Net Total Assets (Liability)	0	0
Netting [Member] | Energy Related Derivative [Member]
Assets
Derivative Assets	-1	-2
Liabilities
Derivative Liability	1	1
Netting [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability		1
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	0
Netting [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	0
Net Fair Value [Member]
Assets
Cash Equivalent	50	15
Restricted Cash	2	2
Rabbi Trust Investments(2)	27	26
Total Assets	79	43
Liabilities
Liabilities	-29	-23
Net Total Assets (Liability)	50	20
Net Fair Value [Member] | Energy Related Derivative [Member]
Assets
Derivative Assets	0	0
Liabilities
Derivative Liability	-24	-17
Net Fair Value [Member] | Energy Contracts - No Regulatory Recovery [Member]
Liabilities
Derivative Liability		0
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	-1	-1
Net Fair Value [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	($4)	($5)

FAIR_VALUE_MEASUREMENTS_AND_DE3

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Sep. 30, 2015
Derivative [Line Items]
Amount Recorded to Capital Lease Interest Expense, Less Than	$0.50	$1
Amount Recorded to Long-Term Debt Interest Expense, Less Than		0.5
Scenario, Forecast [Member]
Derivative [Line Items]
Estimated loss expected to be reclassified to earnings within the next twelve months			$3

FAIR_VALUE_MEASUREMENTS_AND_DE4

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) (Regulatory Recovery [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Regulatory Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	($6)	$1

FAIR_VALUE_MEASUREMENTS_AND_DE5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Mar. 31, 2015	Mar. 31, 2014
	GWh	GWh
Power Contracts (in GWh) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	1,008	2,604
Gas Contracts (in GBtu) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	24,027,000,000	19,932,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) (Level 3 [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$1	$2
Derivative Liability	-13	-11
Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	1	1
Derivative Liability	-8	-6
Market Approach Valuation Technique [Member] | Call Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets		1
Derivative Liability		-1
Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	0	0
Derivative Liability	($5)	($4)
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	23.8	22.35
Minimum [Member] | Market Approach Valuation Technique [Member] | Call Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh		27.75
Market price per MMbtu		2.88
Minimum [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MMbtu	2.34	2.72
Gas volatility	24.15%	30.80%
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	37.7	39.05
Maximum [Member] | Market Approach Valuation Technique [Member] | Call Option [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh		44.94
Market price per MMbtu		4.02
Maximum [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MMbtu	3.22	3.26
Gas volatility	39.91%	53.29%

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
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Fair Value Measurements and Derivative Instruments Disclosure [Abstract]
Beginning balance	($9)	($2)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities - Derivative Instruments	-2	-1
Settlements	-1	1
Ending balance	-12	-2
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	($3)	$0

FAIR_VALUE_MEASUREMENTS_AND_DE8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features	$27,000,000	$21,000,000
Collateral Held from Counterparties	0
Additional collateral if credit-risk contingent features are triggered	27,000,000
Cash Collateral [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	0
Line of Credit Collateral [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$500,000

FAIR_VALUE_MEASUREMENTS_AND_DE9

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt	$1,541,486,000	$1,372,414,000
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$1,642,000,000	$1,457,000,000

RECENTLY_ISSUED_ACCOUNTING_PRO1

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Accounting Policies [Abstract]
Unamortized Debt Issuance Expense	$12	$11
Deferred Finance Costs, Current, Net	$1	$1