Uns Energy (UNS) 10-Q 29 Jul 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Jul. 18, 2014
Entity Information [Line Items]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Jun-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
Trading Symbol	'UNS	'
Entity Registrant Name	'UNS Energy Corp	'
Entity Central Index Key	'0000941138	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'Yes	'
Entity Current Reporting Status	'Yes	'
Entity Voluntary Filer	'No	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	41,701,718
TUCSON ELECTRIC POWER COMPANY	'	'
Entity Information [Line Items]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Entity Registrant Name	'TUCSON ELECTRIC POWER COMPANY	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'No	'
Entity Current Reporting Status	'Yes	'
Entity Voluntary Filer	'No	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	32,139,434

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating Revenues	'	'	'	'
Electric Retail Sales	$302,975	$285,419	$527,545	$506,279
Electric Wholesale Sales	33,309	30,654	76,730	65,052
Gas Retail Sales	21,911	20,013	60,481	71,002
Other Revenue	28,411	29,131	55,242	55,025
Total Operating Revenues	386,606	365,217	719,998	697,358
Operating Expenses	'	'	'	'
Fuel	69,418	86,459	137,253	168,148
Purchased Energy	84,060	57,796	153,843	121,955
Transmission and Other PPFAC Recoverable Costs	6,142	4,521	12,670	7,707
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	-12,517	2,074	-21,437	-3,294
Total Fuel and Purchased Energy	147,103	150,850	282,329	294,516
Operations and Maintenance	91,621	95,143	185,057	185,043
Depreciation	39,563	36,671	78,644	72,970
Amortization	6,455	8,119	12,631	16,408
Taxes Other Than Income Taxes	14,942	13,631	29,750	27,723
Total Operating Expenses	299,684	304,414	588,411	596,660
Operating Income	86,922	60,803	131,587	100,698
Other Income (Deductions)	'	'	'	'
Interest Income	169	19	249	28
Other Income	2,538	1,734	4,680	3,502
Other Expense	-958	-807	-1,688	-1,380
Appreciation in Fair Value of Investments	624	94	879	1,133
Total Other Income (Deductions)	2,373	1,040	4,120	3,283
Interest Expense	'	'	'	'
Long-Term Debt	19,167	17,700	37,055	35,954
Capital Leases	3,925	6,249	7,846	12,498
Other Interest Expense	307	346	790	-47
Interest Capitalized	-1,295	-745	-2,318	-1,420
Interest Expense	22,104	23,550	43,373	46,985
Income Before Income Taxes	67,191	38,293	92,334	56,996
Income Tax Expense	24,837	3,675	34,505	11,033
Net Income	42,354	34,618	57,829	45,963
Weighted-Average Shares of Common Stock Outstanding (000)	'	'	'	'
Basic (in shares)	41,781	41,598	41,759	41,569
Diluted (in shares)	42,145	41,921	42,115	41,898
Earnings Per Share	'	'	'	'
Basic (in dollars per share)	$1.01	$0.83	$1.38	$1.11
Diluted (in dollars per share)	$1.01	$0.83	$1.37	$1.10
Dividends Declared Per Share (usd per share)	$0.48	$0.44	$0.96	$0.87
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Operating Revenues	'	'	'	'
Electric Retail Sales	257,790	243,635	443,805	428,515
Electric Wholesale Sales	32,555	29,542	74,639	63,940
Other Revenue	31,273	31,086	58,687	59,559
Total Operating Revenues	321,618	304,263	577,131	552,014
Operating Expenses	'	'	'	'
Fuel	68,334	84,553	135,964	165,351
Purchased Energy	52,906	28,410	75,521	47,338
Transmission and Other PPFAC Recoverable Costs	3,552	1,730	7,461	2,595
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	-13,061	5,274	-14,791	2,914
Total Fuel and Purchased Energy	111,731	119,967	204,155	218,198
Operations and Maintenance	79,772	82,011	161,117	159,835
Depreciation	31,080	28,861	61,891	57,418
Amortization	7,377	9,052	14,476	18,275
Taxes Other Than Income Taxes	12,005	10,939	23,840	22,108
Total Operating Expenses	241,965	250,830	465,479	475,834
Operating Income	79,653	53,433	111,652	76,180
Other Income (Deductions)	'	'	'	'
Interest Income	165	12	174	8
Other Income	2,187	1,270	4,099	2,438
Other Expense	-2,694	-2,472	-4,809	-4,717
Appreciation in Fair Value of Investments	624	94	879	1,133
Total Other Income (Deductions)	282	-1,096	343	-1,138
Interest Expense	'	'	'	'
Long-Term Debt	15,507	13,991	29,747	28,564
Capital Leases	3,925	6,249	7,846	12,498
Other Interest Expense	140	192	453	-168
Interest Capitalized	-1,104	-534	-2,028	-1,027
Interest Expense	18,468	19,898	36,018	39,867
Income Before Income Taxes	61,467	32,439	75,977	35,175
Income Tax Expense	22,742	1,652	28,080	2,909
Net Income	$38,725	$30,787	$47,897	$32,266

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Net Income	$42,354	$34,618	$57,829	$45,963
Other Comprehensive Income (Loss)	'	'	'	'
Net Changes in Fair Value of Cash Flow Hedges, net of income tax expense benefit	517	933	1,010	1,544
SERP Benefit Amortization, net of income tax expense	25	68	49	137
Total Other Comprehensive Income, Net of Tax	542	1,001	1,059	1,681
Total Comprehensive Income	42,896	35,619	58,888	47,644
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Net Income	38,725	30,787	47,897	32,266
Other Comprehensive Income (Loss)	'	'	'	'
Net Changes in Fair Value of Cash Flow Hedges, net of income tax expense benefit	494	878	975	1,456
SERP Benefit Amortization, net of income tax expense	25	68	49	137
Total Other Comprehensive Income, Net of Tax	519	946	1,024	1,593
Total Comprehensive Income	$39,244	$31,733	$48,921	$33,859

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	$335	$610	$691	$1,009
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	-15	-43	-30	-85
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	321	574	667	952
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	($15)	($43)	($30)	($85)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Cash Flows from Operating Activities	'	'
Cash Receipts from Electric Retail Sales	$531,439	$519,154
Cash Receipts from Electric Wholesale Sales	89,741	82,273
Cash Receipts from Operating Springerville Units 3 & 4	47,099	49,974
Cash Receipts from Gas Retail Sales	80,348	91,207
Cash Receipts from Gas Wholesale Sales	2,287	3,494
Proceeds from Income Tax Refunds	472	0
Interest Received	7	516
Other Cash Receipts	22,812	16,914
Purchased Energy Costs Paid	-152,982	-135,775
Payment of Operations and Maintenance Costs	-138,692	-121,272
Fuel Costs Paid	-135,128	-140,185
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	-86,695	-90,554
Wages Paid, Net of Amounts Capitalized	-72,237	-68,004
Interest Paid, Net of Amounts Capitalized	-31,446	-34,662
Capital Lease Interest Paid	-15,888	-18,630
Other Cash Payments	-3,380	-6,798
Net Cash Flows—Operating Activities	137,757	147,652
Cash Flows from Investing Activities	'	'
Capital Expenditures	-186,037	-155,685
Return of Investments in Springerville Lease Debt	0	9,104
Other, net	-4,345	-3,613
Net Cash Flows—Investing Activities	-190,382	-150,194
Cash Flows from Financing Activities	'	'
Proceeds from Borrowings Under Revolving Credit Facilities	151,000	114,000
Repayments of Borrowings Under Revolving Credit Facilities	-129,000	-48,000
Proceeds from Issuance of Long-Term Debt	149,168	0
Payments of Capital Lease Obligations	-83,204	-84,206
Common Stock Dividends Paid	-40,034	-36,079
Payments of Financing Costs	-1,641	-982
Proceeds from Stock Options Exercised	595	0
Other, net	543	3,584
Net Cash Provided by (Used in) Financing Activities	47,427	-51,683
Cash and Cash Equivalents, Period Increase (Decrease)	-5,198	-54,225
Cash and Cash Equivalents, Beginning of Period	74,878	123,918
Cash and Cash Equivalents, End of Period	69,680	69,693
TUCSON ELECTRIC POWER COMPANY	'	'
Cash Flows from Operating Activities	'	'
Cash Receipts from Electric Retail Sales	444,624	435,779
Cash Receipts from Electric Wholesale Sales	86,087	75,803
Cash Receipts from Operating Springerville Units 3 & 4	47,099	49,974
Reimbursement of Affiliate Charges	13,633	12,695
Cash Receipts from Gas Wholesale Sales	46	3,145
Proceeds from Income Tax Refunds	9	0
Interest Received	5	509
Other Cash Receipts	19,580	13,320
Payment of Operations and Maintenance Costs	-134,606	-117,133
Fuel Costs Paid	-134,374	-139,596
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	-66,588	-68,574
Wages Paid, Net of Amounts Capitalized	-60,845	-57,483
Purchased Power Costs Paid	59,088	40,949
Interest Paid, Net of Amounts Capitalized	-24,588	-27,590
Capital Lease Interest Paid	-15,888	-18,630
Other Cash Payments	-2,064	-5,728
Net Cash Flows—Operating Activities	113,042	115,542
Cash Flows from Investing Activities	'	'
Capital Expenditures	-157,161	-118,210
Return of Investments in Springerville Lease Debt	0	9,104
Other, net	-3,460	-3,470
Net Cash Flows—Investing Activities	-160,621	-112,576
Cash Flows from Financing Activities	'	'
Proceeds from Borrowings Under Revolving Credit Facilities	105,000	78,000
Repayments of Borrowings Under Revolving Credit Facilities	-105,000	-48,000
Proceeds from Issuance of Long-Term Debt	149,168	0
Payments of Capital Lease Obligations	-83,204	-84,206
Payments of Financing Costs	-1,641	-982
Other, net	656	596
Net Cash Provided by (Used in) Financing Activities	64,979	-54,592
Cash and Cash Equivalents, Period Increase (Decrease)	17,400	-51,626
Cash and Cash Equivalents, Beginning of Period	25,335	79,743
Cash and Cash Equivalents, End of Period	$42,735	$28,117

CONDENCED_CONSOLIDATED_BALANCE

CONDENCED CONSOLIDATED BALANCE SHEETS (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Utility Plant	'	'
Plant in Service	$5,392,666	$5,192,122
Utility Plant Under Capital Leases	747,158	637,957
Construction Work in Progress	186,249	201,959
Total Utility Plant	6,326,073	6,032,038
Less Accumulated Depreciation and Amortization	-2,078,626	-1,982,524
Less Accumulated Amortization of Capital Lease Assets	-525,327	-514,677
Total Utility Plant—Net	3,722,120	3,534,837
Investments And Other Property	'	'
Investments in Lease Equity	36,122	36,194
Other	35,551	34,971
Total Investments and Other Property	71,673	71,165
Current Assets	'	'
Cash and Cash Equivalents	69,680	74,878
Accounts Receivable—Customer	114,276	104,596
Unbilled Accounts Receivable	67,637	52,403
Allowance for Doubtful Accounts	-7,001	-6,833
Materials and Supplies	92,771	88,085
Deferred Income Taxes—Current	86,401	66,906
Regulatory Assets—Current	69,322	52,763
Fuel Inventory	44,044	44,317
Derivative Instruments	9,850	5,629
Other	17,453	15,354
Total Current Assets	564,433	498,098
Regulatory and Other Assets	'	'
Regulatory Assets—Noncurrent	162,263	150,584
Derivative Instruments	1,528	1,180
Other Assets	26,575	24,430
Total Regulatory and Other Assets	190,366	176,194
Total Assets	4,548,592	4,280,294
Capitalization	'	'
Common Stock Equity	1,149,578	1,130,784
Capital Lease Obligations	69,938	131,370
Long-Term Debt	1,677,323	1,507,070
Total Capitalization	2,896,839	2,769,224
Current Liabilities	'	'
Current Obligations Under Capital Leases	272,939	186,056
Borrowings Under Revolving Credit Facilities	23,000	22,000
Accounts Payable—Trade	104,720	117,503
Regulatory Liabilities—Current	54,384	53,935
Accrued Taxes Other than Income Taxes	47,601	43,880
Customer Deposits	28,066	30,671
Accrued Employee Expenses	23,202	28,148
Accrued Interest	29,637	27,786
Derivative Instruments	6,435	7,534
Other	22,536	17,775
Total Current Liabilities	612,520	535,288
Deferred Credits and Other Liabilities	'	'
Deferred Income Taxes—Noncurrent	528,636	488,887
Regulatory Liabilities—Noncurrent	326,388	302,482
Pension and Other Retiree Benefits	90,984	90,923
Derivative Instruments	5,976	7,100
Other	87,249	86,390
Total Deferred Credits and Other Liabilities	1,039,233	975,782
Commitments, Contingencies, and Environmental Matters	'	'
Total Capitalization and Other Liabilities	4,548,592	4,280,294
TUCSON ELECTRIC POWER COMPANY	'	'
Utility Plant	'	'
Plant in Service	4,644,399	4,467,667
Utility Plant Under Capital Leases	747,158	637,957
Construction Work in Progress	169,459	180,485
Total Utility Plant	5,561,016	5,286,109
Less Accumulated Depreciation and Amortization	-1,913,655	-1,826,977
Less Accumulated Amortization of Capital Lease Assets	-525,327	-514,677
Total Utility Plant—Net	3,122,034	2,944,455
Investments And Other Property	'	'
Investments in Lease Equity	36,122	36,194
Other	34,192	33,488
Total Investments and Other Property	70,314	69,682
Current Assets	'	'
Cash and Cash Equivalents	42,735	25,335
Accounts Receivable—Customer	96,513	80,211
Unbilled Accounts Receivable	56,252	34,369
Allowance for Doubtful Accounts	-4,977	-4,825
Accounts Receivable, Due from Affiliates	2,818	6,064
Materials and Supplies	79,409	75,200
Deferred Income Taxes—Current	91,585	70,722
Regulatory Assets—Current	59,091	42,555
Fuel Inventory	43,754	44,027
Derivative Instruments	4,289	2,137
Other	14,864	12,923
Total Current Assets	486,333	388,718
Regulatory and Other Assets	'	'
Regulatory Assets—Noncurrent	152,259	141,030
Derivative Instruments	493	167
Other Assets	21,093	19,233
Total Regulatory and Other Assets	173,845	160,430
Total Assets	3,852,526	3,563,285
Capitalization	'	'
Common Stock Equity	974,844	925,923
Capital Lease Obligations	69,938	131,370
Long-Term Debt	1,372,323	1,223,070
Total Capitalization	2,417,105	2,280,363
Current Liabilities	'	'
Current Obligations Under Capital Leases	272,939	186,056
Accounts Payable—Trade	89,162	88,556
Regulatory Liabilities—Current	28,075	23,701
Accounts Payable—Due to Affiliates	5,282	9,153
Accrued Taxes Other than Income Taxes	39,732	34,485
Customer Deposits	20,906	21,354
Accrued Employee Expenses	19,726	24,454
Accrued Interest	24,651	22,785
Derivative Instruments	4,261	5,531
Other	13,641	9,244
Total Current Liabilities	518,375	425,319
Deferred Credits and Other Liabilities	'	'
Deferred Income Taxes—Noncurrent	464,983	428,103
Regulatory Liabilities—Noncurrent	283,475	263,270
Pension and Other Retiree Benefits	84,724	84,936
Derivative Instruments	4,907	5,161
Other	78,957	76,133
Total Deferred Credits and Other Liabilities	917,046	857,603
Commitments, Contingencies, and Environmental Matters	'	'
Total Capitalization and Other Liabilities	$3,852,526	$3,563,285

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	TUCSON ELECTRIC POWER COMPANY	Common Shares Outstanding [Member]	Common Stock [Member]	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Accumulated Other Comprehensive Loss [Member]
In Thousands, unless otherwise specified	USD ($)	USD ($)		USD ($)	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	USD ($)	TUCSON ELECTRIC POWER COMPANY	USD ($)	TUCSON ELECTRIC POWER COMPANY
					USD ($)	USD ($)		USD ($)		USD ($)
Balances at Dec. 31, 2013	$1,130,784	$925,923	'	$889,301	$888,971	($6,357)	$247,532	$49,185	($6,049)	($5,876)
Balances, shares at Dec. 31, 2013	'	'	41,538	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	57,829	47,897	'	'	'	'	57,829	47,897	'	'
Other Comprehensive Loss, net of tax	1,059	1,024	'	'	'	'	'	'	1,059	1,024
Dividends Declared	-40,372	'	'	'	'	'	-40,372	'	'	'
Shares Issued for Stock Options, shares	'	'	20	'	'	'	'	'	'	'
Shares Issued for Stock Options	594	'	'	594	'	'	'	'	'	'
Shares Issued Under Performance Share Awards, shares	'	'	101	'	'	'	'	'	'	'
Shares Issued Under Performance Share Awards	0	'	'	0	'	'	'	'	'	'
Share-based Compensation	-316	'	'	-316	'	'	'	'	'	'
Balances at Jun. 30, 2014	1,149,578	974,844	'	889,579	888,971	-6,357	264,989	97,082	-4,990	-4,852
Balances, shares at Jun. 30, 2014	'	'	41,659	'	'	'	'	'	'	'
Balances at Mar. 31, 2014	'	'	'	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	42,354	38,725	'	'	'	'	'	'	'	'
Other Comprehensive Loss, net of tax	542	519	'	'	'	'	'	'	'	'
Balances at Jun. 30, 2014	$1,149,578	$974,844	'	'	$888,971	($6,357)	'	'	'	'

CONSOLIDATED_STATEMENT_OF_CHAN1

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (Parenthetical)	Jun. 30, 2014
Common Stock, Shares Authorized	75,000,000

NATURE_OF_OPERATIONS_AND_FINAN

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION
	UNS Energy Corporation (UNS Energy) is a holding company that conducts its business through three regulated public utilities: Tucson Electric Power Company (TEP); UNS Electric, Inc. (UNS Electric); and UNS Gas, Inc. (UNS Gas) (collectively Regulated Utilities). References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
	We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K.
	The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results. UNS Energy and TEP reclassified certain amounts in the financial statements to conform to current year presentation.
	REVISION OF PRIOR PERIOD BALANCE SHEETS
	UNS Energy and TEP revised their December 31, 2013 balance sheets to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements.
	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2014, we adopted accounting guidance that:
	•	requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.
	•	impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.

PENDING_MERGER_WITH_FORTIS

PENDING MERGER WITH FORTIS	6 Months Ended
	Jun. 30, 2014
Business Combinations [Abstract]	'
PENDING MERGER WITH FORTIS INC.	'
	PENDING MERGER WITH FORTIS
	On December 11, 2013, UNS Energy announced that it had entered into an Agreement and Plan of Merger (Merger), subject to shareholder and required regulatory approvals, to be acquired by Fortis Inc. (Fortis) for $60.25 per share of Common Stock in cash. Following the Merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Boards of Directors of each of UNS Energy and Fortis have approved the Merger.
	The following additional approvals have been received:
	•	In March 2014, UNS Energy's shareholders approved the Merger;
	•	In April 2014, the Federal Energy Regulatory Commission (FERC) approved the Merger;
	•	In May 2014, the Committee on Foreign Investment in the United States concluded its review determining there are no unresolved national security concerns with respect to the Merger;
	•	In June 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and
	•	In July 2014, the Federal Communications Commission approved UNS Energy’s FCC license transfer of control applications with respect to the Merger.
	The final regulatory approval necessary to complete the Merger is approval by the Arizona Corporation Commission (ACC). In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a settlement (Settlement) in which the parties agree that the Merger is in the public interest and recommend approval by the ACC, subject to certain conditions. Those conditions include, but are not limited to, the following:
	•	UNS Energy shall provide credits on the Regulated Utilities retail customers' bills totaling $30 million over five years; $10 million in year one and $5 million annually in years two through five. The monthly bill credits will be applied each year from October through March. If the Merger closes by the end of September 2014, the bill credits will commence on October 1, 2014;
	•	UNS Energy and the Regulated Utilities will adopt certain ring-fencing and corporate governance provisions;
	•	Dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014; and
	•	Fortis shall make an equity investment totaling $220 million through UNS Energy into the Regulated Utilities following closing of the Merger. However, if the Merger closes after September 30, 2014, the equity investment may be made into UNS Energy to retire debt.
	The Settlement is subject to the review and approval of the ACC, which could approve, reject, or require modifications to the Settlement as a condition of approval of the Merger. Hearings before an ACC administrative law judge on the Settlement concluded on June 17, 2014. The Settlement requests that the ACC issue an order approving the Settlement no later than September 18, 2014.
	The completion of the Merger is also subject to the absence of any injunction, order, or other law prohibiting the Merger.
	If the Merger is approved by the ACC in September 2014 as requested by the parties to the Settlement Agreement, we expect the Merger to close by the end of September 2014. Upon completion of the Merger, UNS Energy expects to record approximately $19 million of merger-related expenses including investment banker fees, legal fees, and accelerated expenses for certain share-based compensation awards. TEP would record approximately $15 million as its allocated share of these merger-related expenses. See Note 9.

REGULATORY_MATTERS

REGULATORY MATTERS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
REGULATORY MATTERS	'
	REGULATORY MATTERS
	The ACC and the FERC each regulate portions of the utility accounting practices and rates of the Regulated Utilities.
	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. The Merger with Fortis is subject to approval by the ACC. See Note 2. Additionally, the purchase of Gila River Generating Station Unit 3 (Gila River Unit 3) remains subject to FERC approval. See Note 7.
	COST RECOVERY MECHANISMS
	TEP Purchased Power and Fuel Adjustment Clause
	In April 2014, the ACC approved a Purchased Power and Fuel Adjustment Clause (PPFAC) rate for TEP of 0.1 cents per kWh for the period May through September 2014 and 0.5 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was a credit of 0.14 cents per kWh for the period July 2013 through April 2014.
	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. At June 30, 2014, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.
	TEP Environmental Compliance Adjustor
	The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP expects to recognize ECA revenues of less than $1 million in 2014.
	UNS Electric Transmission Cost Adjustor
	The 2013 UNS Electric Rate Order provided a Transmission Cost Adjustor (TCA) that allows more timely recovery of transmission costs associated with serving retail customers. The TCA rate is adjusted annually based on information filed with the ACC each May. The TCA rate of 0.114 cents per kWh became effective in June 2014.
	UNS Gas Purchased Gas Adjustor
	In November of 2013, a Purchased Gas Adjustor (PGA) credit of 10 cents per therm became effective for UNS Gas. The credit expired in April 2014.
	Energy Efficiency Standards
	The Regulated Utilities are required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as a performance incentive. In the first half of 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Sales in the UNS Energy and TEP income statements.
	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 energy efficiency programs and distributed generation targets. During separate rate case proceedings in 2013, the ACC authorized LFCR mechanisms for TEP and UNS Electric, subject to a year-over-year cap of 1% of each company’s respective total retail revenues.
	TEP and UNS Electric filed their first LFCR reports with the ACC in May 2014. TEP requested recovery of approximately $5 million and UNS Electric requested recovery of approximately $1 million. The LFCR rates are expected to go into effect in August 2014 for TEP and in September 2014 for UNS Electric.
	TEP and UNS Electric recorded LFCR revenues of $6 million and $2 million, respectively, in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. We recognize LFCR revenue when verifiable regardless of when the lost retail kWh sales occur. LFCR revenue is included in Electric Retail Sales in the income statements.

BUSINESS_SEGMENTS

BUSINESS SEGMENTS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
BUSINESS SEGMENTS	'
	BUSINESS SEGMENTS
	We have three reportable segments regularly reviewed by our chief operating decision makers to evaluate performance and make operating decisions.
	-1	TEP, a regulated electric utility and our largest subsidiary
	-2	UNS Electric, a regulated electric utility
	-3	UNS Gas, a regulated gas distribution utility
	We disclose selected financial data for our reportable segments in the following tables:
		Reportable Segments
		TEP		UNS Electric		UNS Gas		Other (2)			Reconciling			UNS
											Adjustments			Energy
		Millions of Dollars
	Three Months Ended June 30, 2014
	Operating Revenues-External	$	318	$	47	$	22	$	—		$	—		$	387
	Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
	Income Before Income Taxes	61		6		—		—			—			67
	Net Income	39		4		—		(1		)	—			42
	Three Months Ended June 30, 2013
	Operating Revenues-External	$	300	$	44	$	21	$	—		$	—		$	365
	Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
	Income Before Income Taxes	32		6		—		—			—			38
	Net Income	31		4		—		—			—			35
		Reportable Segments
		TEP		UNS Electric		UNS Gas		Other (2)			Reconciling			UNS
											Adjustments			Energy
		Millions of Dollars
	Six Months Ended June 30, 2014
	Operating Revenues-External	$	569	87		64		$	—		$	—		$	720
	Operating Revenues-Intersegment (1)	8		1		1		8			(18		)	—
	Income Before Income Taxes	76		9		8		(1		)	—			92
	Net Income	48		6		5		(1		)	—			58
	Six Months Ended June 30, 2013
	Operating Revenues-External	$	543	$	80	$	73	$	1		$	—		$	697
	Operating Revenues-Intersegment (1)	9		1		1		8			(19		)	—
	Income Before Income Taxes	35		9		13		—			—			57
	Net Income	32		6		8		—			—			46
	(1)	Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.
	(2)	Other includes the UNS Energy and UES holding companies, Millennium, and UED.

DEBT_CREDIT_FACILITIES_AND_CAP

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	'
	DEBT AND CAPITAL LEASE OBLIGATIONS
	We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2013 Annual Report on Form 10-K.
	TEP SPRINGERVILLE COAL HANDLING FACILITIES CAPITAL LEASE PURCHASE COMMITMENT
	In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, TEP recorded, in April of 2014, an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment.
	TEP previously agreed with Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at June 30, 2014.
	2014 TEP UNSECURED NOTES ISSUED
	In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may call the debt prior to September 15, 2043, with a make-whole premium plus accrued interest. After September 15, 2043, TEP may call the debt at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the revolving credit facility, with the remaining proceeds to be applied to general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.
	TEP CREDIT AGREEMENT
	The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility and an $82 million LOC facility to support tax-exempt bonds. As of June 30, 2014, there is $184 million available under the revolving credit facility. The TEP Credit Agreement expires in November 2016. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.
	TEP provided, in the second quarter of 2014, a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 7.
	COVENANT COMPLIANCE
	At June 30, 2014, we were in compliance with the terms of our loan and credit agreements.

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	'
	COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
	COMMITMENTS
	UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas. In addition to those reported in our 2013 Annual Report on Form 10-K, UNS Energy entered into the following long-term commitments through June 30, 2014:
		UNS Energy Purchase Commitments
		2014		2015		2016		2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, including Transportation	$	—	$	9	$	9	$	9	$	8	$	8	$	43
	Purchased Power	—		23		—		—		—		—		23
	Capital Lease Obligations(1)	—		120		—		—		—		—		120
	Total Purchase Commitments	$	—	$	152	$	9	$	9	$	8	$	8	$	186
	TEP entered into the following long-term commitments:
		TEP Purchase Commitments
		2014		2015		2016		2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	—	$	8	$	8	$	8	$	8	$	8	$	40
	Purchased Power	—		15		—		—		—		—		15
	Capital Lease Obligations(1)	—		120		—		—		—		—		120
	Total Purchase Commitments	$	—	$	143	$	8	$	8	$	8	$	8	$	175
	(1)	In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.
	UNS ENERGY CONTINGENCIES
	In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a Settlement in which the Regulated Utilities agreed, contingent upon completion of the Merger, to provide credits on retail customers' bills totaling $30 million over five years. See Note 2.
	TEP CONTINGENCIES
	Planned Purchase of Gas-Fired Generation Facility
	In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.
	Claim Related to San Juan Generating Station
	San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
	In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.
	Claims Related to Four Corners Generating Station
	In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The joint participants have agreed to have the matter stayed until August 2014 in furtherance of settlement talks.
	TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. 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 loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.
	In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. The New Mexico Taxation and Revenue Department and APS started settlement negotiations in July 2014. TEP cannot predict the outcome or timing of resolution of this claim.
	Mine Closure Reclamation at Generating Stations Not Operated by TEP
	TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $20 million at June 30, 2014 and $18 million at December 31, 2013.
	Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
	TEP’s PPFAC allows us to pass through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
	Discontinued Transmission Project
	TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. TEP and UNS Electric plan to keep the path approved in the line siting matter in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from 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.
	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 June 30, 2014, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements expire in 2016 through 2046.
	UNS ELECTRIC CONTINGENCIES
	Planned Purchase of Gas-Fired Generation Facility
	In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.
	ENVIRONMENTAL MATTERS
	Environmental Regulation
	The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
	Hazardous Air Pollutant Requirements
	In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATS) rules, additional emission control equipment will be required by April 2015. TEP has received an extension until April 2016 to comply with the MATS rules at Springerville. The operator of Navajo has also received an extension until April 2016. TEP's share of the estimated costs to comply with the MATS rules include the following:
	Estimated Mercury Emissions Control Costs:	Navajo		Four Corners		Springerville(1)
		Millions of Dollars
	Capital Expenditures	$	1	$	1	$	5
	Annual O&M Expenses	1		1		1
	-1	Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
	TEP expects Sundt and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules.
	Regional Haze Rules
	The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
	In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the BART rules apply to plants built prior to Springerville. TEP cannot predict the ultimate outcome of these matters.
	TEP's estimated costs involved in meeting these rules are:
	Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
		Millions of Dollars
	Capital Expenditures	$	42	$	35	$	35	$	12
	Annual O&M Expenses	1		1		2		6-May
	-1	The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.
	-2	The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.
-3	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
(4) In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

PLANNED_PURCHASE_OF_GASFIRED_G

PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY	6 Months Ended
	Jun. 30, 2014
Other Commitments [Abstract]	'
OTHER COMMITMENTS	'
	PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY
	In December 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to FERC approval and other closing conditions.
	In December 2013, UNS Electric filed an application for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3. The application is still pending before the ACC.
	In June 2014, TEP provided a letter of credit (LOC) for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. The seller is entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the purchase agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
EMPLOYEE BENEFIT PLANS	'
	EMPLOYEE BENEFIT PLANS
	UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:
		Pension Benefits						Other Retiree Benefits
		Three Months Ended June 30,
		2014			2013			2014		2013
		Millions of Dollars
	Service Cost	$	2		$	3		$	1	$	1
	Interest Cost	5			4			—		1
	Expected Return on Plan Assets	(5		)	(5		)	—		—
	Actuarial Loss Amortization	1			2			—		—
	Net Periodic Benefit Cost	$	3		$	4		$	1	$	2
		Pension Benefits						Other Retiree Benefits
		Six Months Ended June 30,
		2014			2013			2014		2013
		Millions of Dollars
	Service Cost	$	5		$	6		$	2	$	2
	Interest Cost	9			8			1		1
	Expected Return on Plan Assets	(11		)	(10		)	—		—
	Actuarial Loss Amortization	2			4			—		—
	Net Periodic Benefit Cost	$	5		$	8		$	3	$	3

SHAREBASED_COMPENSATION_PLANS

SHARE-BASED COMPENSATION PLANS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
SHARE-BASED COMPENSATION PLANS	'
	SHARE-BASED COMPENSATION PLANS
	RESTRICTED STOCK UNITS
	In May 2014, the UNS Energy Compensation Committee (Compensation Committee) granted 7,486 restricted stock units to non-employee directors at a grant date fair value, based on the grant date closing share price, of $60.11 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. We issue UNS Energy Common Stock (Common Stock) for the vested restricted stock units at the time elected by each of the non-employee directors based on certain eligibility requirements. These restricted stock units accrue dividend equivalents during and subsequent to the vesting period, which are distributed in shares of Common Stock at the same time as the related restricted stock units.
	In February 2014, the Compensation Committee granted 16,910 restricted stock units to certain management employees at a grant date fair value, based on the grant date closing share price, of $60.39 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.
	PERFORMANCE SHARES
	In February 2014, the Compensation Committee granted 33,820 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $57.47 per share. Those awards will be paid out in Common Stock based on UNS Energy’s compound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period ended December 31, 2016. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date closing share price, of $60.39 per share and will be paid out in Common Stock based on cumulative net income for the three-year performance period ended December 31, 2016. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.
	The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.
	SHARE-BASED COMPENSATION EXPENSE
	UNS Energy and TEP recorded share-based compensation expense of less than $1 million for the three months ended June 30, 2014 and June 30, 2013. For the six months ended June 30, 2014, UNS Energy recorded share-based compensation expense of $2 million, $1 million of which related to TEP. For the six months ended June 30, 2013, UNS Energy and TEP recorded share-based compensation expense of $1 million.
	At June 30, 2014, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, of which $4 million are allocable to TEP, which will be recorded as compensation expense over the remaining vesting periods through February 2017. The completion of the Merger would result in accelerated vesting and expense recognition for these awards. See Note 2. At June 30, 2014, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.

UNS_ENERGY_EARNINGS_PER_SHARE

UNS ENERGY EARNINGS PER SHARE	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
UNS ENERGY EARNINGS PER SHARE	'
	UNS ENERGY EARNINGS PER SHARE
	We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options or share-based compensation awards were exercised or converted into Common Stock. We excluded anti-dilutive contingently issuable shares from the calculation of diluted EPS.
	The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:
		Three Months Ended June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
		Thousands of Dollars
	Numerator: Net Income	$	42,354	$	34,618	$	57,829	$	45,963
		Thousands of Shares
	Denominator:
	Weighted Average Shares of Common Stock Outstanding:
	Common Shares Issued	41,659		41,427		41,639		41,404
	Fully Vested Deferred Stock Units	122		171		120		165
	Total Weighted Average Common Stock Outstanding — Basic	41,781		41,598		41,759		41,569
	Effect of Dilutive Securities:
	Options and Stock Issuable Under Share-Based Compensation Plans	364		323		356		329
	Total Weighted Average Common Stock Outstanding — Diluted	42,145		41,921		42,115		41,898
	For the six months ended June 30, 2013, we excluded 12,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive.

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
SUPPLEMENTAL CASH FLOW INFORMATION	'
	SUPPLEMENTAL CASH FLOW INFORMATION
	A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:
		UNS Energy
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Net Income	$	57,829		$	45,963
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	78,644			72,970
	Amortization Expense	12,631			16,408
	Depreciation and Amortization Recorded to Fuel and O&M Expense	3,977			3,516
	Amortization of Deferred Debt-Related Costs included in Interest Expense	1,584			1,515
	Provision for Retail Customer Bad Debts	1,194			936
	Use of Renewable Energy Credits for Compliance	11,313			8,106
	Deferred Income Taxes	36,320			36,644
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11,039		)
	Pension and Retiree Expense	7,884			11,391
	Pension and Retiree Funding	(5,974		)	(8,924		)
	Share-Based Compensation Expense	1,859			1,390
	Allowance for Equity Funds Used During Construction	(4,038		)	(2,463		)
	LFCR Revenue	(7,654		)	—
	Decrease to Reflect PPFAC/PGA Recovery	(21,437		)	(3,294		)
	PPFAC Reduction - 2013 TEP Rate Order	—			3,000
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(22,766		)	(20,706		)
	Materials and Fuel Inventory	(4,413		)	8,777
	Accounts Payable	(5,875		)	(9,576		)
	Income Taxes	(88		)	(15,980		)
	Interest Accrued	1,305			(6,885		)
	Taxes Other Than Income Taxes	3,721			490
	Other	(8,259		)	15,413
	Net Cash Flows – Operating Activities	$	137,757		$	147,652
		TEP
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Net Income	$	47,897		$	32,266
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	61,891			57,418
	Amortization Expense	14,476			18,275
	Depreciation and Amortization Recorded to Fuel and O&M Expense	3,406			2,987
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,285			1,216
	Provision for Retail Customer Bad Debts	833			711
	Use of Renewable Energy Credits for Compliance	9,884			7,414
	Deferred Income Taxes	29,641			24,883
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(10,751		)
	Pension and Retiree Expense	6,824			9,939
	Pension and Retiree Funding	(5,522		)	(8,493		)
	Share-Based Compensation Expense	1,496			1,108
	Allowance for Equity Funds Used During Construction	(3,524		)	(1,763		)
	LFCR Revenue	(6,121		)	—
	Increase (Decrease) to Reflect PPFAC Recovery	(14,791		)	2,914
	PPFAC Reduction - 2013 TEP Rate Order	—			3,000
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(35,498		)	(30,452		)
	Materials and Fuel Inventory	(3,936		)	8,923
	Accounts Payable	6,019			(11		)
	Income Taxes	(6		)	(10,798		)
	Interest Accrued	1,320			(6,886		)
Taxes Other Than Income Taxes	5,247			2,295
Other	(7,779		)	11,347
Net Cash Flows – Operating Activities	$	113,042		$	115,542
NON-CASH TRANSACTIONS
In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase lease interests in April 2015. See Note 5.
In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction.

FAIR_VALUE_MEASUREMENTS_AND_DE

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS	'
	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
	We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.
	FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
	The following tables present, by level within the fair value hierarchy, UNS Energy’s and 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.
		UNS Energy
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Jun-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	13			$	13			$	—			$	—			$	—		$	13
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	23				—				23				—				—			23
	Energy Contracts - Regulatory Recovery(3)	11				—				5				6				(3		)	8
	Total Assets	49				15				28				6				(3		)	46
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(5		)		—				(1		)		(4		)		3			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(6		)		—				(6		)		—				—			(6		)
	Total Liabilities	(12		)		—				(7		)		(5		)		3			(9		)
	Net Total Assets (Liabilities)	$	37			$	15			$	21			$	1			$	—		$	37
		UNS Energy
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	14			$	14			$	—			$	—			$	—		$	14
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	7				—				3				4				(5		)	2
	Total Assets	45				16				25				4				(5		)	40
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(7		)		—				(2		)		(5		)		5			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
	Total Liabilities	(15		)		—				(9		)		(6		)		5			(10		)
	Net Total Assets (Liabilities)	$	30			$	16			$	16			$	(2	)		$	—		$	30
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Jun-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—			$	—			$	—		$	—
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	23				—				23				—				—			23
	Energy Contracts - Regulatory Recovery(3)	5				—				2				3				(2		)	3
	Total Assets	30				2				25				3				(2		)	28
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(3		)		—				(1		)		(2		)		2			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(6		)		—				(6		)		—				—			(6		)
	Total Liabilities	(10		)		—				(7		)		(3		)		2			(8		)
	Net Total Assets (Liabilities)	$	20			$	2			$	18			$	—			$	—		$	20
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—			$	—			$	—		$	—
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	2				—				1				1				(1		)	1
	Total Assets	26				2				23				1				(1		)	25
	Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)		—				—				(2		)		1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
Total Liabilities	(10		)		—				(7		)		(3		)		1			(9		)
Net Total Assets (Liabilities)	$	16			$	2			$	16			$	(2	)		$	—		$	16
(1)	Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
(2)	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
(3)	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
-4	Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.
(5)	All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.
DERIVATIVE INSTRUMENTS
We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA.
We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.
For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.
We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. In the first half of 2013, we also used this pricing model to value our power options.
We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.
Our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our price curves monthly.
Cash Flow Hedges
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 14. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million for UNS Energy and TEP.
Financial Impact of Energy Contracts
We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:
	UNS Energy								TEP
	Three Months Ended June 30,
	2014				2013				2014				2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	1			$	(9	)		$	2			$	(3	)
	UNS Energy								TEP
	Six Months Ended June 30,
	2014				2013				2014				2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	5			$	—			$	2			$	(1	)
Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At June 30, 2014, UNS Energy and TEP have energy contracts that will settle through the second quarter of 2017.
Derivative Volumes
The volumes associated with our energy contracts were as follows:
	UNS Energy						TEP
	June 30, 2014			December 31, 2013			June 30, 2014			December 31, 2013
Power Contracts GWh	1,933			1,583			976			779
Gas Contracts GBtu	63,546			33,371			27,176			9,615
Level 3 Fair Value Measurements
The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:
			Fair Value at
			30-Jun-14										Range of
	Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Contracts(1)	Market approach		$	4			$	(4	)		Market price per MWh		$	23.9		-	$	57.9
Option Contracts(2)	Option model		2				(1		)		Market price per MMbtu		$	3.87		-	$	4.57
											Gas volatility		21.01		%	-	32.1		%
Level 3 Energy Contracts			$	6			$	(5	)
			Fair Value at
			31-Dec-13										Range of
	Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Contracts(3)	Market approach		$	1			$	(4	)		Market price per MWh		$	26.54		-	$	51.75
Option Contracts(4)	Option model		3				(2		)		Market price per MMbtu		$	3.87		-	$	4.32
											Gas volatility		25.05		%	-	35.07		%
Level 3 Energy Contracts			$	4			$	(6	)
(1)	TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.
(2)	TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.
(3)	TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities at December 31, 2013.
(4)	TEP comprises less than $1 million of the option contract assets at December 31, 2013.
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC or PGA mechanisms 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:
	UNS Energy				TEP
	Three Months Ended June 30, 2014
	Millions of Dollars
Balances at March 31, 2014	$	—			$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	3				2
Settlements	(2		)		—
Balances at June 30, 2014	$	1			$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	3			$	3
	UNS Energy				TEP
	Six Months Ended June 30, 2014
	Millions of Dollars
Balances at December 31, 2013	$	(2	)		$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	5				1
Settlements	(2		)		1
Balances at June 30, 2014	$	1			$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	2			$	1
	UNS Energy				TEP
	Three Months Ended June 30, 2013
	Millions of Dollars
Balances at March 31, 2013	$	(3	)		$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)		—
Settlements	—				—
Balances at June 30, 2013	$	(5	)		$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(4	)		$	—
	UNS Energy				TEP
	Six Months Ended June 30, 2013
	Millions of Dollars
Balances at December 31, 2012	$	(5	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)		(1		)
Settlements	2				—
Balances at June 30, 2013	$	(5	)		$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(3	)		$	(1	)
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to the Regulated Utilities; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.
We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.
Material adverse changes could trigger credit risk-related contingent features. At June 30, 2014, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $25 million for UNS Energy and $19 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $25 million for UNS Energy and $19 million for TEP.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:
•	The carrying amounts of our current maturities of long-term debt and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.
•	For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.
•	For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
			30-Jun-14								31-Dec-13
	Fair Value		Carrying				Fair				Carrying				Fair
	Hierarchy		Value				Value				Value				Value
			Millions of Dollars
Assets:
TEP Investment in Lease Equity	Level 3		$	36			$	25			$	36			$	25
Liabilities:
Long-Term Debt
UNS Energy	Level 2		$	1,677			$	1,771			$	1,507			$	1,521
TEP	Level 2		1,372				1,435				1,223				1,214

INCOME_TAXES_INCOME_TAXES

INCOME TAXES INCOME TAXES	6 Months Ended
	Jun. 30, 2014
Income Tax Disclosure [Abstract]	'
Income Tax Disclosure [Text Block]	'
	INCOME TAXES
	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		UNS Energy						TEP
		Three Months Ended June 30,
		2014			2013			2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	24		$	14		$	22		$	12
	State Income Tax Expense, Net of Federal Deduction	3			2			3			2
	Federal/State Tax Credits	(2		)	—			(2		)	—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
	Other	—			(1		)	—			(1		)
	Total Federal and State Income Tax Expense	$	25		$	4		$	23		$	2
		UNS Energy						TEP
		Six Months Ended June 30,
		2014			2013			2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	32		$	20		$	27		$	12
	State Income Tax Expense, Net of Federal Deduction	4			3			3			2
	Federal/State Tax Credits	(2		)	—			(2		)	—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
	Other	1			(1		)	—			—
	Total Federal and State Income Tax Expense	$	35		$	11		$	28		$	3
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset
	Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.

RECLASSIFICATIONS_FROM_ACCUMUL

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT	6 Months Ended
	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]	'
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT	'
	RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT
	The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:
		UNS Energy
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Three Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(349	)	$	(346	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	430			451
	Realized Losses on Cash Flow Hedges, Net of Taxes	(664		)	(690		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(40		)	(111		)	Operations and Maintenance
	Tax Benefit	15			43
	Amortization, Net of Taxes	(25		)	(68		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(689	)	$	(758	)
		UNS Energy
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(702	)	$	(676	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	734			820
	Realized Losses on Cash Flow Hedges, Net of Taxes	(1,309		)	(1,255		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(79		)	(222		)	Operations and Maintenance
	Tax Benefit	30			85
	Amortization, Net of Taxes	(49		)	(137		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(1,358	)	$	(1,392	)
		TEP
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Three Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(293	)	$	(293	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	408			429
	Realized Losses on Cash Flow Hedges, Net of Taxes	(630		)	(659		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(40		)	(111		)	Other Expense
	Tax Benefit	15			43
	Amortization, Net of Taxes	(25		)	(68		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(655	)	$	(727	)
		TEP
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(591	)	$	(575	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	692			781
	Realized Losses on Cash Flow Hedges, Net of Taxes	(1,240		)	(1,193		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(79		)	(222		)	Other Expense
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,289	)	$	(1,330	)

RECENTLY_ISSUED_ACCOUNTING_PRO

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	'
	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
	In April 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.
	In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.

NATURE_OF_OPERATIONS_AND_FINAN1

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
Reclassification, Policy	'
	REVISION OF PRIOR PERIOD BALANCE SHEETS
	UNS Energy and TEP revised their December 31, 2013 balance sheets to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements.
Recently Adopted Accounting Pronouncements	'
	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2014, we adopted accounting guidance that:
	•	requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.
	•	impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.

BUSINESS_SEGMENTS_Tables

BUSINESS SEGMENTS (Tables)	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
Reconciling Adjustments of Income Statement Items in Consolidation	'
	We disclose selected financial data for our reportable segments in the following tables:
		Reportable Segments
		TEP		UNS Electric		UNS Gas		Other (2)			Reconciling			UNS
											Adjustments			Energy
		Millions of Dollars
	Three Months Ended June 30, 2014
	Operating Revenues-External	$	318	$	47	$	22	$	—		$	—		$	387
	Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
	Income Before Income Taxes	61		6		—		—			—			67
	Net Income	39		4		—		(1		)	—			42
	Three Months Ended June 30, 2013
	Operating Revenues-External	$	300	$	44	$	21	$	—		$	—		$	365
	Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
	Income Before Income Taxes	32		6		—		—			—			38
	Net Income	31		4		—		—			—			35
		Reportable Segments
		TEP		UNS Electric		UNS Gas		Other (2)			Reconciling			UNS
											Adjustments			Energy
		Millions of Dollars
	Six Months Ended June 30, 2014
	Operating Revenues-External	$	569	87		64		$	—		$	—		$	720
	Operating Revenues-Intersegment (1)	8		1		1		8			(18		)	—
	Income Before Income Taxes	76		9		8		(1		)	—			92
	Net Income	48		6		5		(1		)	—			58
	Six Months Ended June 30, 2013
	Operating Revenues-External	$	543	$	80	$	73	$	1		$	—		$	697
	Operating Revenues-Intersegment (1)	9		1		1		8			(19		)	—
	Income Before Income Taxes	35		9		13		—			—			57
	Net Income	32		6		8		—			—			46
	(1)	Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.
	(2)	Other includes the UNS Energy and UES holding companies, Millennium, and UED.

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Unrecorded Unconditional Purchase Obligations Disclosure	'
	In addition to those reported in our 2013 Annual Report on Form 10-K, UNS Energy entered into the following long-term commitments through June 30, 2014:
		UNS Energy Purchase Commitments
		2014		2015		2016		2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, including Transportation	$	—	$	9	$	9	$	9	$	8	$	8	$	43
	Purchased Power	—		23		—		—		—		—		23
	Capital Lease Obligations(1)	—		120		—		—		—		—		120
	Total Purchase Commitments	$	—	$	152	$	9	$	9	$	8	$	8	$	186
	TEP entered into the following long-term commitments:
		TEP Purchase Commitments
		2014		2015		2016		2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	—	$	8	$	8	$	8	$	8	$	8	$	40
	Purchased Power	—		15		—		—		—		—		15
	Capital Lease Obligations(1)	—		120		—		—		—		—		120
	Total Purchase Commitments	$	—	$	143	$	8	$	8	$	8	$	8	$	175
	(1)	In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.
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	$	42	$	35	$	35	$	12
	Annual O&M Expenses	1		1		2		6-May
	-1	The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.
	-2	The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.
	-3	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
	(4) In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.
	TEP's share of the estimated costs to comply with the MATS rules include the following:
	Estimated Mercury Emissions Control Costs:	Navajo		Four Corners		Springerville(1)
		Millions of Dollars
	Capital Expenditures	$	1	$	1	$	5
	Annual O&M Expenses	1		1		1
	-1	Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
Components of Net Periodic Benefit Cost	'
	UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:
		Pension Benefits						Other Retiree Benefits
		Three Months Ended June 30,
		2014			2013			2014		2013
		Millions of Dollars
	Service Cost	$	2		$	3		$	1	$	1
	Interest Cost	5			4			—		1
	Expected Return on Plan Assets	(5		)	(5		)	—		—
	Actuarial Loss Amortization	1			2			—		—
	Net Periodic Benefit Cost	$	3		$	4		$	1	$	2
		Pension Benefits						Other Retiree Benefits
		Six Months Ended June 30,
		2014			2013			2014		2013
		Millions of Dollars
	Service Cost	$	5		$	6		$	2	$	2
	Interest Cost	9			8			1		1
	Expected Return on Plan Assets	(11		)	(10		)	—		—
	Actuarial Loss Amortization	2			4			—		—
	Net Periodic Benefit Cost	$	5		$	8		$	3	$	3

UNS_ENERGY_EARNINGS_PER_SHARE_

UNS ENERGY EARNINGS PER SHARE (Tables)	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
Effects of Dilutive Common Stock on Weighted-Average Number of Shares	'
	The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:
		Three Months Ended June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
		Thousands of Dollars
	Numerator: Net Income	$	42,354	$	34,618	$	57,829	$	45,963
		Thousands of Shares
	Denominator:
	Weighted Average Shares of Common Stock Outstanding:
	Common Shares Issued	41,659		41,427		41,639		41,404
	Fully Vested Deferred Stock Units	122		171		120		165
	Total Weighted Average Common Stock Outstanding — Basic	41,781		41,598		41,759		41,569
	Effect of Dilutive Securities:
	Options and Stock Issuable Under Share-Based Compensation Plans	364		323		356		329
	Total Weighted Average Common Stock Outstanding — Diluted	42,145		41,921		42,115		41,898
Shares of Common Stock Excluded from Computation of Diluted Earning Per Share	'
	For the six months ended June 30, 2013, we excluded 12,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive.

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
Schedule of Cash Flow, Supplemental Disclosures	'
	A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:
		UNS Energy
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Net Income	$	57,829		$	45,963
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	78,644			72,970
	Amortization Expense	12,631			16,408
	Depreciation and Amortization Recorded to Fuel and O&M Expense	3,977			3,516
	Amortization of Deferred Debt-Related Costs included in Interest Expense	1,584			1,515
	Provision for Retail Customer Bad Debts	1,194			936
	Use of Renewable Energy Credits for Compliance	11,313			8,106
	Deferred Income Taxes	36,320			36,644
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11,039		)
	Pension and Retiree Expense	7,884			11,391
	Pension and Retiree Funding	(5,974		)	(8,924		)
	Share-Based Compensation Expense	1,859			1,390
	Allowance for Equity Funds Used During Construction	(4,038		)	(2,463		)
	LFCR Revenue	(7,654		)	—
	Decrease to Reflect PPFAC/PGA Recovery	(21,437		)	(3,294		)
	PPFAC Reduction - 2013 TEP Rate Order	—			3,000
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(22,766		)	(20,706		)
	Materials and Fuel Inventory	(4,413		)	8,777
	Accounts Payable	(5,875		)	(9,576		)
	Income Taxes	(88		)	(15,980		)
	Interest Accrued	1,305			(6,885		)
	Taxes Other Than Income Taxes	3,721			490
	Other	(8,259		)	15,413
	Net Cash Flows – Operating Activities	$	137,757		$	147,652
		TEP
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Net Income	$	47,897		$	32,266
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	61,891			57,418
	Amortization Expense	14,476			18,275
	Depreciation and Amortization Recorded to Fuel and O&M Expense	3,406			2,987
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,285			1,216
	Provision for Retail Customer Bad Debts	833			711
	Use of Renewable Energy Credits for Compliance	9,884			7,414
	Deferred Income Taxes	29,641			24,883
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(10,751		)
	Pension and Retiree Expense	6,824			9,939
	Pension and Retiree Funding	(5,522		)	(8,493		)
	Share-Based Compensation Expense	1,496			1,108
	Allowance for Equity Funds Used During Construction	(3,524		)	(1,763		)
	LFCR Revenue	(6,121		)	—
	Increase (Decrease) to Reflect PPFAC Recovery	(14,791		)	2,914
	PPFAC Reduction - 2013 TEP Rate Order	—			3,000
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(35,498		)	(30,452		)
	Materials and Fuel Inventory	(3,936		)	8,923
	Accounts Payable	6,019			(11		)
	Income Taxes	(6		)	(10,798		)
	Interest Accrued	1,320			(6,886		)
	Taxes Other Than Income Taxes	5,247			2,295
Other	(7,779		)	11,347
Net Cash Flows – Operating Activities	$	113,042		$	115,542

FAIR_VALUE_MEASUREMENTS_AND_DE1

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	6 Months Ended
	Jun. 30, 2014
Text Block [Abstract]	'
Schedule of Fair Value Measurements of Financial Assets and Liabilities	'
	The following tables present, by level within the fair value hierarchy, UNS Energy’s and 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.
		UNS Energy
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Jun-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	13			$	13			$	—			$	—			$	—		$	13
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	23				—				23				—				—			23
	Energy Contracts - Regulatory Recovery(3)	11				—				5				6				(3		)	8
	Total Assets	49				15				28				6				(3		)	46
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(5		)		—				(1		)		(4		)		3			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(6		)		—				(6		)		—				—			(6		)
	Total Liabilities	(12		)		—				(7		)		(5		)		3			(9		)
	Net Total Assets (Liabilities)	$	37			$	15			$	21			$	1			$	—		$	37
		UNS Energy
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	14			$	14			$	—			$	—			$	—		$	14
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	7				—				3				4				(5		)	2
	Total Assets	45				16				25				4				(5		)	40
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(7		)		—				(2		)		(5		)		5			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
	Total Liabilities	(15		)		—				(9		)		(6		)		5			(10		)
	Net Total Assets (Liabilities)	$	30			$	16			$	16			$	(2	)		$	—		$	30
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Jun-14
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—			$	—			$	—		$	—
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	23				—				23				—				—			23
	Energy Contracts - Regulatory Recovery(3)	5				—				2				3				(2		)	3
	Total Assets	30				2				25				3				(2		)	28
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(3		)		—				(1		)		(2		)		2			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(6		)		—				(6		)		—				—			(6		)
	Total Liabilities	(10		)		—				(7		)		(3		)		2			(8		)
	Net Total Assets (Liabilities)	$	20			$	2			$	18			$	—			$	—		$	20
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—			$	—			$	—		$	—
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	2				—				1				1				(1		)	1
	Total Assets	26				2				23				1				(1		)	25
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(2		)		—				—				(2		)		1			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
Total Liabilities	(10		)		—				(7		)		(3		)		1			(9		)
Net Total Assets (Liabilities)	$	16			$	2			$	16			$	(2	)		$	—		$	16
(1)	Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
(2)	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
(3)	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
-4	Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.
(5)	All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.
Financial Impact of Energy Contracts	'
	We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:
		UNS Energy								TEP
		Three Months Ended June 30,
		2014				2013				2014				2013
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	1			$	(9	)		$	2			$	(3	)
		UNS Energy								TEP
		Six Months Ended June 30,
		2014				2013				2014				2013
		Millions of Dollars
	Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	5			$	—			$	2			$	(1	)
Derivative Volumes	'
	The volumes associated with our energy contracts were as follows:
		UNS Energy						TEP
		June 30, 2014			December 31, 2013			June 30, 2014			December 31, 2013
	Power Contracts GWh	1,933			1,583			976			779
	Gas Contracts GBtu	63,546			33,371			27,176			9,615
Quantitative Information Regarding Unobservable Inputs	'
	The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:
				Fair Value at
				30-Jun-14										Range of
		Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Contracts(1)	Market approach		$	4			$	(4	)		Market price per MWh		$	23.9		-	$	57.9
	Option Contracts(2)	Option model		2				(1		)		Market price per MMbtu		$	3.87		-	$	4.57
												Gas volatility		21.01		%	-	32.1		%
	Level 3 Energy Contracts			$	6			$	(5	)
				Fair Value at
				31-Dec-13										Range of
		Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Contracts(3)	Market approach		$	1			$	(4	)		Market price per MWh		$	26.54		-	$	51.75
	Option Contracts(4)	Option model		3				(2		)		Market price per MMbtu		$	3.87		-	$	4.32
												Gas volatility		25.05		%	-	35.07		%
	Level 3 Energy Contracts			$	4			$	(6	)
	(1)	TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.
	(2)	TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.
	(3)	TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities at December 31, 2013.
	(4)	TEP comprises less than $1 million of the option contract assets at December 31, 2013.
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:
		UNS Energy				TEP
		Three Months Ended June 30, 2014
		Millions of Dollars
	Balances at March 31, 2014	$	—			$	(2	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	3				2
	Settlements	(2		)		—
	Balances at June 30, 2014	$	1			$	—
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	3			$	3
		UNS Energy				TEP
		Six Months Ended June 30, 2014
		Millions of Dollars
	Balances at December 31, 2013	$	(2	)		$	(2	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	5				1
	Settlements	(2		)		1
	Balances at June 30, 2014	$	1			$	—
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	2			$	1
		UNS Energy				TEP
		Three Months Ended June 30, 2013
		Millions of Dollars
	Balances at March 31, 2013	$	(3	)		$	(1	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)		—
	Settlements	—				—
	Balances at June 30, 2013	$	(5	)		$	(1	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(4	)		$	—
		UNS Energy				TEP
		Six Months Ended June 30, 2013
		Millions of Dollars
	Balances at December 31, 2012	$	(5	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)		(1		)
	Settlements	2				—
	Balances at June 30, 2013	$	(5	)		$	(1	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(3	)		$	(1	)
Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments	'
	The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
				30-Jun-14								31-Dec-13
		Fair Value		Carrying				Fair				Carrying				Fair
		Hierarchy		Value				Value				Value				Value
				Millions of Dollars
	Assets:
	TEP Investment in Lease Equity	Level 3		$	36			$	25			$	36			$	25
	Liabilities:
	Long-Term Debt
	UNS Energy	Level 2		$	1,677			$	1,771			$	1,507			$	1,521
	TEP	Level 2		1,372				1,435				1,223				1,214

INCOME_TAXES_INCOME_TAXES_Tabl

INCOME TAXES INCOME TAXES (Tables)	6 Months Ended
	Jun. 30, 2014
Income Tax Disclosure [Abstract]	'
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		UNS Energy						TEP
		Three Months Ended June 30,
		2014			2013			2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	24		$	14		$	22		$	12
	State Income Tax Expense, Net of Federal Deduction	3			2			3			2
	Federal/State Tax Credits	(2		)	—			(2		)	—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
	Other	—			(1		)	—			(1		)
	Total Federal and State Income Tax Expense	$	25		$	4		$	23		$	2
		UNS Energy						TEP
		Six Months Ended June 30,
		2014			2013			2014			2013
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	32		$	20		$	27		$	12
	State Income Tax Expense, Net of Federal Deduction	4			3			3			2
	Federal/State Tax Credits	(2		)	—			(2		)	—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
	Other	1			(1		)	—			—
	Total Federal and State Income Tax Expense	$	35		$	11		$	28		$	3

RECLASSIFICATIONS_FROM_ACCUMUL1

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)	6 Months Ended
	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:
		UNS Energy
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Three Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(349	)	$	(346	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	430			451
	Realized Losses on Cash Flow Hedges, Net of Taxes	(664		)	(690		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(40		)	(111		)	Operations and Maintenance
	Tax Benefit	15			43
	Amortization, Net of Taxes	(25		)	(68		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(689	)	$	(758	)
		UNS Energy
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(702	)	$	(676	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	734			820
	Realized Losses on Cash Flow Hedges, Net of Taxes	(1,309		)	(1,255		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(79		)	(222		)	Operations and Maintenance
	Tax Benefit	30			85
	Amortization, Net of Taxes	(49		)	(137		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(1,358	)	$	(1,392	)
		TEP
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Three Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(293	)	$	(293	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	408			429
	Realized Losses on Cash Flow Hedges, Net of Taxes	(630		)	(659		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(40		)	(111		)	Other Expense
	Tax Benefit	15			43
	Amortization, Net of Taxes	(25		)	(68		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(655	)	$	(727	)
		TEP
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		Six Months Ended June 30,
		2014			2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(591	)	$	(575	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
	Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
	Tax Benefit	692			781
	Realized Losses on Cash Flow Hedges, Net of Taxes	(1,240		)	(1,193		)
	Amortization of SERP
	Prior Service Cost and Net Loss	(79		)	(222		)	Other Expense
	Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,289	)	$	(1,330	)

NATURE_OF_OPERATIONS_AND_FINAN2

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Additional Information) (Detail) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014
Deferred Income Taxes Current And Noncurrent [Member]	'
Quantifying Misstatement in Current Year Financial Statements, Amount	$7
Deferred Income Taxes Current And Noncurrent [Member] | TUCSON ELECTRIC POWER COMPANY	'
Quantifying Misstatement in Current Year Financial Statements, Amount	7
Capital Lease Obligation Current And Noncurrent [Member]	'
Quantifying Misstatement in Current Year Financial Statements, Amount	18
Capital Lease Obligation Current And Noncurrent [Member] | TUCSON ELECTRIC POWER COMPANY	'
Quantifying Misstatement in Current Year Financial Statements, Amount	$18

PENDING_MERGER_WITH_FORTIS_Pen

PENDING MERGER WITH FORTIS (Pending Merger With Fortis) (Details) (USD $)	Jun. 30, 2014	Dec. 11, 2013	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014
In Millions, except Per Share data, unless otherwise specified		Fortis Inc	Total Bill Credit Refunds Over 5 Years [Member]	Bill Credit Refunds in Year 1 [Member]	Annual Bill Credit Refunds in Years 1Through 5 [Member]	May Through September [Member]
						TUCSON ELECTRIC POWER COMPANY
Business Acquisition [Line Items]	'	'	'	'	'	'
Share price	'	$60.25	'	'	'	'
Customer Bill Credits Required Per Merger Settlement Agreement Subject to Regulatory Approval	'	'	$30	$10	$5	'
Dividend Restrictions Per Merger Settlement Agreement Pending Regulatory Approval	60.00%	'	'	'	'	'
Required Equity Capitalization for Regulated Utilities Prior to Dividend Payment	50.00%	'	'	'	'	'
Required Equity Investment By Acquiring Company Per Merger Settlement Agreement Subject to Regulatory Approval	220	'	'	'	'	'
Merger-Related Costs Expected Upon Closing of Merger Subject to Regulatory Approval	$19	'	'	'	'	$15

REGULATORY_MATTERS_Cost_Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) (USD $)

1 Months Ended

6 Months Ended

1 Months Ended

6 Months Ended

10 Months Ended

1 Months Ended

6 Months Ended

1 Months Ended

12 Months Ended

Apr. 30, 2014

Jun. 30, 2014

31-May-14

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Apr. 30, 2014

Jun. 30, 2014

31-May-14

Jun. 30, 2014

Apr. 30, 2014

Apr. 30, 2014

Dec. 31, 2014

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Electric

UNS Electric

UNS Electric

May Through September [Member]

October Through March [Member]

Scenario, Forecast [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Schedule of Regulatory Cost Recovery Mechanisms [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

PPFAC Rate

'

'

'

'

'

'

0.0014

'

'

'

0.001

0.005

'

Mine Fire Cost Deferral

'

'

'

'

$10,000,000

'

'

'

'

'

'

'

'

Mine Fire Insurance Settlement Proceeds

'

'

'

'

8,000,000

'

'

'

'

'

'

'

'

Environmental Compliance Adjustor Rate

'

'

0.000049

'

'

'

'

'

'

'

'

'

'

Regulated Operating Revenue, Other

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

Transmission Cost Adjustor Rate

'

'

'

'

'

'

'

0.00114

'

'

'

'

'

Purchased Gas Adjustor Credit

0.1

'

'

'

'

'

'

'

'

'

'

'

'

Energy Efficiency Performance Incentive

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

Cap on increase in lost fixed cost recovery rate

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

Lost Fixed Cost Recovery Requested

'

'

5,000,000

'

'

'

'

'

1,000,000

'

'

'

'

Revenue Recognized Under Lost Fixed Cost Recovery Mechanism

'

$7,654,000

'

'

$6,121,000

$0

'

'

'

$2,000,000

'

'

'

BUSINESS_SEGMENTS_Reporting_De

BUSINESS SEGMENTS (Reporting) (Details)	6 Months Ended
	Jun. 30, 2014
	Segment
Segment Reporting [Abstract]	'
Number of Reportable Segments	3

BUSINESS_SEGMENTS_Reconciliati

BUSINESS SEGMENTS (Reconciliation of Income Statement Items from Segments to Consolidation) (Detail) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	$386,606,000		$365,217,000		$719,998,000		$697,358,000
Operating Revenues-Intersegment	0	[1]	0	[1]	0	[1]	0
Income Before Income Taxes	67,191,000		38,293,000		92,334,000		56,996,000
Net Income	42,354,000		34,618,000		57,829,000		45,963,000
Reconciling Adjustments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	0		0		0		0
Operating Revenues-Intersegment	-9,000,000	[1]	-9,000,000	[1]	-18,000,000	[1]	-19,000,000
Income Before Income Taxes	0		0		0		0
Net Income	0		0		0		0
TUCSON ELECTRIC POWER COMPANY | Operating Segments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	318,000,000		300,000,000		569,000,000		543,000,000
Operating Revenues-Intersegment	4,000,000	[1]	4,000,000	[1]	8,000,000	[1]	9,000,000
Income Before Income Taxes	61,467,000		32,439,000		75,977,000		35,000
Net Income	38,725,000		30,787,000		47,897,000		32,266,000
UNS Electric | Operating Segments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	47,000,000		44,000,000		87,000,000		80,000,000
Operating Revenues-Intersegment	0	[1]	0	[1]	1,000,000	[1]	1,000,000	[1]
Income Before Income Taxes	6,000,000		6,000,000		9,000,000		9,000,000
Net Income	4,000,000		4,000,000		6,000,000		6,000,000
UNS Gas | Operating Segments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	22,000,000		21,000,000		64,000,000		73,000,000
Operating Revenues-Intersegment	1,000,000	[1]	1,000,000	[1]	1,000,000	[1]	1,000,000
Income Before Income Taxes	0		0		8,000,000		13,000,000
Net Income	0		0		5,000,000		8,000,000
Other | Operating Segments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	0		0		0	[2]	1,000,000
Operating Revenues-Intersegment	4,000,000	[1]	4,000,000	[1]	8,000,000	[1],[2]	8,000,000
Income Before Income Taxes	0		0		-1,000,000		0
Net Income	($1,000,000)		$0		($1,000,000)	[2]	$0
[1]	Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.
[2]	Other includes the UNS Energy and UES holding companies, Millennium, and UED.

DEBT_CREDIT_FACILITIES_AND_CAP1

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Details) (TUCSON ELECTRIC POWER COMPANY, Springerville Coal Handling Facilities Lease [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014
TUCSON ELECTRIC POWER COMPANY | Springerville Coal Handling Facilities Lease [Member]	'
Debt Instrument [Line Items]	'
Increase in Capital Lease Obligation	$109
Fixed price to acquire leased interest in facilities	120
Increase in utility plant under capital lease	109
Sales Price of Leased Interest In Facilities	$24

DEBT_CREDIT_FACILITIES_AND_CAP2

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Debt) (Detail) (USD $)	6 Months Ended						1 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Jun. 30, 2014	Jun. 30, 2014	Jul. 18, 2014
			TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	Revolving Credit Facility [Member]	Revolving Credit Facility [Member]	Letter of Credit [Member]	Subsequent Event [Member]
					Unsecured Debt [Member]	Unsecured Debt [Member]	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	Revolving Credit Facility [Member]
										TUCSON ELECTRIC POWER COMPANY
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'
Debt instrument, face amount	'	'	'	'	$150,000,000	$91,000,000	'	'	'	'
Fixed interest rate of long-term debt	'	'	'	'	5.00%	'	'	'	'	'
Repayment of outstanding credit facility	129,000,000	48,000,000	105,000,000	48,000,000	'	'	90,000,000	'	'	'
Line of Credit Facility, Maximum Borrowing Capacity	'	'	'	'	'	'	'	200,000,000	82,000,000	'
Line of Credit Facility, Remaining Borrowing Capacity	'	'	'	'	'	'	'	184,000,000	'	134,000,000
Guaranty Liabilities	'	'	'	'	'	'	'	'	15,000,000	'
Letters of Credit Outstanding, Amount	'	'	'	'	'	'	'	'	$15,000,000	'

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Commitments) (Details) (USD $)	Jun. 30, 2014
In Millions, unless otherwise specified
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	$0
2015	152
2016	9
2017	9
2018	8
Thereafter	8
Total	186
Springerville Coal Handling Facilities Lease [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0	[1]
2015	120	[1]
2016	0	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Total	120	[1]
Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	9
2016	9
2017	9
2018	8
Thereafter	8
Total	43
Purchased Power [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	23
2016	0
2017	0
2018	0
Thereafter	0
Total	23
TUCSON ELECTRIC POWER COMPANY	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	143
2016	8
2017	8
2018	8
Thereafter	8
Total	175
TUCSON ELECTRIC POWER COMPANY | Springerville Coal Handling Facilities Lease [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0	[1]
2015	120	[1]
2016	0	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Total	120	[1]
TUCSON ELECTRIC POWER COMPANY | Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	8
2016	8
2017	8
2018	8
Thereafter	8
Total	40
TUCSON ELECTRIC POWER COMPANY | Purchased Power [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	0
2015	15
2016	0
2017	0
2018	0
Thereafter	0
Total	$15
[1]	(1) In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (UNS & TEP Contingencies) (Detail) (USD $)

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

In Millions, unless otherwise specified

San Juan [Member]

Tucson to Nogales [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member]

Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member]

Assessment for Coal Severance Tax, Coal Supplier [Member]

Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member]

Total Bill Credit Refunds Over 5 Years [Member]

mi

San Juan [Member]

Four Corner [Member]

Tucson to Nogales [Member]

Tucson to Nogales [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

San Juan [Member]

San Juan [Member]

Four Corner [Member]

Four Corner [Member]

Commitments And Contingencies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Customer Bill Credits Required Per Merger Settlement Agreement Subject to Regulatory Approval

'

'

'

'

'

'

'

'

'

'

'

'

$30

Percentage of ownership in generating station

'

'

'

'

50.00%

7.00%

'

'

'

'

'

'

'

Percentage Of Ownership In Generating Units

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

Estimate of Possible Loss Contingency

'

'

'

'

'

'

'

'

5

1

30

1

'

TEP accrued an estimated loss related to Four Corners Generating Station

'

'

'

'

'

1

'

'

'

'

'

'

'

TEP's share of reclamation costs at expiration dates of the coal supply agreements

'

'

44

'

'

'

'

'

'

'

'

'

'

TEP's recorded obligations for final mine reclamation costs

'

'

20

18

'

'

'

'

'

'

'

'

'

Transmission line from Tucson to Nogales

'

60

'

'

'

'

'

'

'

'

'

'

'

Transmission Line, in KV

'

345

'

'

'

'

'

'

'

'

'

'

'

Asset Impairment Charges

'

'

'

'

'

'

5

'

'

'

'

'

'

Regulatory Assets

'

'

'

'

'

'

'

$5

'

'

'

'

'

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Environmental Matters) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014
Navajo [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	$1
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Estimated Capital Expenditure for Selective Catalytic Reduction	42	[1]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1	[1]
Better Than BART Agreement Year by which to Shut Down One Unit	'2020
Better than BART Agreement, Year by which SCR Technology to be Installed	'2030
Better than BART Agreement, Year by which Coal Fired Operation will Cease	'2044
Estimated Capital Expenditure Related to Installation of Baghouses	43
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses	1
Jointly Owned Utility Plant, Proportionate Ownership Share	7.50%
Four Corner [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	1
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Estimated Capital Expenditure for Selective Catalytic Reduction	35	[2]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2	[2]
Jointly Owned Utility Plant, Proportionate Ownership Share	7.00%
Springerville [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	5	[3]
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1	[3]
San Juan [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Capital Expenditure for Selective Non Catalytic Reduction	35	[4]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	6
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1	[4]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Jointly Owned Utility Plant, Net Ownership Amount	112
San Juan [Member] | Minimum [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Capital Expenditure for Selective Catalytic Reduction	180
San Juan [Member] | Maximum [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Capital Expenditure for Selective Catalytic Reduction	200
Sundt [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12	[5]
Jointly Owned Utility Plant, Net Ownership Amount	27
Sundt [Member] | Minimum [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5	[5]
Sundt [Member] | Maximum [Member]	'
Commitments And Contingencies [Line Items]	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	$6	[5]
[1]	The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.
[2]	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
[3]	Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
[4]	The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.
[5]	In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

PLANNED_PURCHASE_OF_GASFIRED_G1

PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY (Additional Information) (Details) (Entegra, Gila River Generating Station Unit 3 [Member], USD $)	Dec. 23, 2013
In Millions, unless otherwise specified	MW
Unusual or Infrequent Item [Line Items]	'
Planned Purchase of Gas-Fired Generation Facility	$219
Generating capacity of plant in MW	550
TUCSON ELECTRIC POWER COMPANY	'
Unusual or Infrequent Item [Line Items]	'
Planned Purchase of Gas-Fired Generation Facility	164
Generating capacity of plant in MW	413
Percentage of ownership in Generating Unit	75.00%
UNS ELECTRIC, INC.	'
Unusual or Infrequent Item [Line Items]	'
Planned Purchase of Gas-Fired Generation Facility	$55
Generating capacity of plant in MW	137
Percentage of ownership in Generating Unit	25.00%

EMPLOYEE_BENEFIT_PLANS_Compone

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Benefits [Member]	'	'	'	'
Components of Net Periodic Benefit Plan Cost	'	'	'	'
Service Cost	$2	$3	$5	$6
Interest Cost	5	4	9	8
Expected Return on Plan Assets	-5	-5	-11	-10
Amortization of Actuarial (Gain) Loss	-1	-2	-2	-4
Net Periodic Benefit Plan Cost	3	4	5	8
Other Retiree Benefits [Member]	'	'	'	'
Components of Net Periodic Benefit Plan Cost	'	'	'	'
Service Cost	1	1	2	2
Interest Cost	0	1	1	1
Expected Return on Plan Assets	0	0	0	0
Amortization of Actuarial (Gain) Loss	0	0	0	0
Net Periodic Benefit Plan Cost	$1	$2	$3	$3

SHAREBASED_COMPENSATION_PLANS_

SHARE-BASED COMPENSATION PLANS (Restricted Stock Units) (Detail) (Restricted Stock [Member], USD $)	1 Months Ended
	31-May-14	Feb. 28, 2014
	Director [Member]	Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Granted, Shares	7,486	16,910
Grant Date Fair Value	$60.11	$60.39

SHAREBASED_COMPENSATION_PLANS_1

SHARE-BASED COMPENSATION PLANS (Summary of Performance Shares Awarded and Grant Date Fair Value) (Detail) (USD $)	1 Months Ended
	Feb. 28, 2014
Performance Share Awards [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Granted, Shares	33,820
Market Condition Awards [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Grant Date Fair Value	57.47
Performance Condition [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Grant Date Fair Value	60.39

SHAREBASED_COMPENSATION_PLANS_2

SHARE-BASED COMPENSATION PLANS (Additional Information) (Detail) (USD $)	3 Months Ended		6 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Share based compensation expense, net of amounts capitalized	$1	$1	$2	$1
Total unrecognized compensation expense on non-vested share-based compensation	5	'	5	'
Number Of Shares Awarded But Not Yet Issued	500,000	'	500,000	'
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Share based compensation expense, net of amounts capitalized	1	1	1	1
Total unrecognized compensation expense on non-vested share-based compensation	$4	'	$4	'

Effects_of_Dilutive_Common_Sto

(Effects of Dilutive Common Stock on Weighted-Average Number of Shares) (Detail) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Numerator:	'	'	'	'
Net Income	$42,354	$34,618	$57,829	$45,963
Weighted Average Shares of Common Stock Outstanding:	'	'	'	'
Common Shares Issued	41,659	41,427	41,639	41,404
Fully Vested Deferred Stock Units	122	171	120	165
Total Weighted Average Shares of Common Stock Outstanding and Participating Securities - Basic	41,781	41,598	41,759	41,569
Effect of Dilutive Securities:	'	'	'	'
Options and Stock Issuable Under Share-Based Compensation Plans	364	323	356	329
Total Shares - Diluted	42,145	41,921	42,115	41,898

Shares_of_Common_Stock_Exclude

(Shares of Common Stock Excluded from Computation of Diluted Earning Per Share) (Detail)	6 Months Ended
	Jun. 30, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	12,000

SUPPLEMENTAL_CASH_FLOW_INFORMA2

SUPPLEMENTAL CASH FLOW INFORMATION (Reconciliation of Net Income to Net Cash Flows from Operating Activities) (Detail) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Supplemental Cash Flow Information [Line Items]	'	'	'	'
Net Income	$42,354	$34,618	$57,829	$45,963
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities	'	'	'	'
Depreciation Expense	39,563	36,671	78,644	72,970
Amortization Expense	6,455	8,119	12,631	16,408
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	'	'	3,977	3,516
Amortization of Deferred Debt-Related Costs Included in Interest Expense	'	'	1,584	1,515
Provision for Retail Customer Bad Debts	'	'	1,194	936
Use of RECs for Compliance	'	'	11,313	8,106
Deferred Income Taxes	'	'	36,320	36,644
Investment Tax Credit Basis Adjustment	0	-11,000	0	-11,039
Pension and Postretirement Expense	'	'	7,884	11,391
Pension and Postretirement Funding	'	'	-5,974	-8,924
Share-Based Compensation Expense	'	'	1,859	1,390
Allowance for Equity Funds Used During Construction	'	'	-4,038	-2,463
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism	'	'	-7,654	'
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	-12,517	2,074	-21,437	-3,294
PPFAC Reduction - 2013 TEP Rate Order	'	'	0	3,000
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately	'	'	'	'
Accounts Receivable	'	'	-22,766	-20,706
Materials and Fuel Inventory	'	'	-4,413	8,777
Accounts Payable	'	'	-5,875	-9,576
Income Taxes	'	'	-88	-15,980
Interest Accrued	'	'	1,305	-6,885
Taxes Other Than Income Taxes	'	'	3,721	490
Other	'	'	-8,259	15,413
Net Cash Flows—Operating Activities	'	'	137,757	147,652
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Supplemental Cash Flow Information [Line Items]	'	'	'	'
Net Income	38,725	30,787	47,897	32,266
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities	'	'	'	'
Depreciation Expense	31,080	28,861	61,891	57,418
Amortization Expense	7,377	9,052	14,476	18,275
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	'	'	3,406	2,987
Amortization of Deferred Debt-Related Costs Included in Interest Expense	'	'	1,285	1,216
Provision for Retail Customer Bad Debts	'	'	833	711
Use of RECs for Compliance	'	'	9,884	7,414
Deferred Income Taxes	'	'	29,641	24,883
Investment Tax Credit Basis Adjustment	0	-11,000	0	-10,751
Pension and Postretirement Expense	'	'	6,824	9,939
Pension and Postretirement Funding	'	'	-5,522	-8,493
Share-Based Compensation Expense	'	'	1,496	1,108
Allowance for Equity Funds Used During Construction	'	'	-3,524	-1,763
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism	'	'	-6,121	0
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	-13,061	5,274	-14,791	2,914
PPFAC Reduction - 2013 TEP Rate Order	'	'	0	3,000
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately	'	'	'	'
Accounts Receivable	'	'	-35,498	-30,452
Materials and Fuel Inventory	'	'	-3,936	8,923
Accounts Payable	'	'	6,019	-11
Income Taxes	'	'	-6	-10,798
Interest Accrued	'	'	1,320	-6,886
Taxes Other Than Income Taxes	'	'	5,247	2,295
Other	'	'	-7,779	11,347
Net Cash Flows—Operating Activities	'	'	$113,042	$115,542

SUPPLEMENTAL_CASH_FLOW_INFORMA3

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) (TUCSON ELECTRIC POWER COMPANY, USD $)	1 Months Ended
	Apr. 30, 2014	Mar. 31, 2014	Mar. 31, 2013
	Springerville Unit One Lease [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]
Increase in Capital Lease Obligation	$109,000,000	'	'
Increase in Utility Plant under Capital Lease	109,000,000	'	'
Debt instrument, face amount	'	$150,000,000	$91,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE2

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $)	Jun. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Assets	'		'
Cash Equivalent	$13	[1]	$14	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	11	[3]	7	[3]
Total Assets	49		45
Liabilities	'		'
Liabilities	-12		-15
Net Total Assets (Liability)	37		30
Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-5	[3]	-7	[3]
Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-6	[4]	-7	[4]
TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	5	[3]	2	[3]
Total Assets	30		26
Liabilities	'		'
Liabilities	-10		-10
Net Total Assets (Liability)	20		16
TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-3	[3]	-2	[3]
TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-6	[4]	-7	[4]
Level 1 [Member]	'		'
Assets	'		'
Cash Equivalent	13	[1]	14	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	0	[3]	0	[3]
Total Assets	15		16
Liabilities	'		'
Liabilities	0		0
Net Total Assets (Liability)	15		16
Level 1 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	0	[3]	0	[3]
Total Assets	2		2
Liabilities	'		'
Liabilities	0		0
Net Total Assets (Liability)	2		2
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Level 2 [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	5	[3]	3	[3]
Total Assets	28		25
Liabilities	'		'
Liabilities	-7		-9
Net Total Assets (Liability)	21		16
Level 2 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-6	[4]	-7	[4]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	2	[3]	1	[3]
Total Assets	25		23
Liabilities	'		'
Liabilities	-7		-7
Net Total Assets (Liability)	18		16
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-6	[4]	-7	[4]
Level 3 [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	6	[3]	4	[3]
Total Assets	6		4
Liabilities	'		'
Derivative Liability	-5		-6
Liabilities	-5		-6
Net Total Assets (Liability)	1		-2
Level 3 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-4	[3]	-5	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
Level 3 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	3	[3]	1	[3]
Total Assets	3		1
Liabilities	'		'
Liabilities	-3		-3
Net Total Assets (Liability)	0		-2
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[3]	-2	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Netting [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Derivative Assets	-3	[3],[5]	-5	[3],[5]
Total Assets	-3	[5]	-5	[5]
Liabilities	'		'
Liabilities	3	[5]	5	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	3	[3],[5]	5	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4],[5]	0	[4],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Derivative Assets	-2	[3],[5]	-1	[3],[5]
Total Assets	-2	[5]	-1	[5]
Liabilities	'		'
Liabilities	2	[5]	1	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	2	[3],[5]	1	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4],[5]	0	[4],[5]
Net Fair Value [Member]	'		'
Assets	'		'
Cash Equivalent	13	[1]	14	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	8	[3]	2	[3]
Total Assets	46		40
Liabilities	'		'
Liabilities	-9		-10
Net Total Assets (Liability)	37		30
Net Fair Value [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[3]	-2	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-6	[4]	-7	[4]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	3	[3]	1	[3]
Total Assets	28		25
Liabilities	'		'
Liabilities	-8		-9
Net Total Assets (Liability)	20		16
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-1	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	($6)	[4]	($7)	[4]
[1]	Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
[2]	Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
[3]	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
[4]	Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.
[5]	All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

FAIR_VALUE_MEASUREMENTS_AND_DE3

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014
Derivative [Line Items]	'
Estimated loss expected to be reclassified to earnings within the next twelve months	$3
TUCSON ELECTRIC POWER COMPANY	'
Derivative [Line Items]	'
Estimated loss expected to be reclassified to earnings within the next twelve months	$3

FAIR_VALUE_MEASUREMENTS_AND_DE4

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$1	($9)	$5	$0
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$2	($3)	$2	($1)

FAIR_VALUE_MEASUREMENTS_AND_DE5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Jun. 30, 2014	Dec. 31, 2013
	GWh	GWh
Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	1,933	1,583
Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	63,546,000,000	33,371,000,000
TUCSON ELECTRIC POWER COMPANY | Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	976	779
TUCSON ELECTRIC POWER COMPANY | Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	27,176,000,000	9,615,000,000

FAIR_VALUE_MEASUREMENTS_AND_DE6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) (USD $)	Jun. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	$11	[1]	$7	[1]
Level 3 [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	6	[1]	4	[1]
Derivative Liability	-5		-6
Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	4	[2]	1	[2]
Derivative Liability	-4	[2]	-4	[2]
Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	2	[3]	3	[3]
Derivative Liability	-1	[3]	-2	[3]
Minimum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MWh	23.9		26.54
Minimum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MMbtu	3.87		3.87
Gas volatility	21.01%		25.05%
Maximum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MWh	57.9		51.75
Maximum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MMbtu	4.57		4.32
Gas volatility	32.10%		35.07%
TUCSON ELECTRIC POWER COMPANY	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	5	[1]	2	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	3	[1]	1	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	2	[2]	'
Derivative Liability	-2	[2]	'
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Valuation Technique Option Model [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	'		1	[2]
Derivative Liability	'		-3	[2]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Derivative Assets	1		1
Derivative Liability	($1)		'
[1]	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
[2]	TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.
[3]	TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.

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		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'	'
Beginning balance	$0	($3)	($2)	($5)
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	3	-2	5	-2
Settlements	-2	0	-2	2
Ending balance	1	-5	1	-5
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	3	-4	2	-3
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'	'
Beginning balance	-2	-1	-2	0
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	2	0	1	-1
Settlements	0	0	1	0
Ending balance	0	-1	0	-1
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	$3	$0	$1	($1)

FAIR_VALUE_MEASUREMENTS_AND_DE8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $)	Jun. 30, 2014
In Millions, unless otherwise specified
Derivative [Line Items]	'
Fair value of derivative instruments	$25
Additional collateral if credit-risk contingent features are triggered	25
TUCSON ELECTRIC POWER COMPANY	'
Derivative [Line Items]	'
Fair value of derivative instruments	19
Additional collateral if credit-risk contingent features are triggered	$19

FAIR_VALUE_MEASUREMENTS_AND_DE9

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Liabilities:	'	'
Long-Term Debt	$1,677,323,000	$1,507,070,000
TUCSON ELECTRIC POWER COMPANY	'	'
Liabilities:	'	'
Long-Term Debt	1,372,323,000	1,223,070,000
Carrying Value [Member] | Level 2 [Member]	'	'
Liabilities:	'	'
Long-Term Debt	1,677,000,000	1,507,000,000
Carrying Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Liabilities:	'	'
Long-Term Debt	1,372,000,000	1,223,000,000
Carrying Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Assets:	'	'
TEP Investment in Lease Equity	36,000,000	36,000,000
Fair Value [Member] | Level 2 [Member]	'	'
Liabilities:	'	'
Long-Term Debt	1,771,000,000	1,521,000,000
Fair Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Liabilities:	'	'
Long-Term Debt	1,435,000,000	1,214,000,000
Fair Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Assets:	'	'
TEP Investment in Lease Equity	$25,000,000	$25,000,000

INCOME_TAXES_Effective_Income_

INCOME TAXES (Effective Income Tax Rate Reconciliation) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Taxes [Line Items]	'	'	'	'
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$24,000,000	$14,000,000	$32,000,000	$20,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	3,000,000	2,000,000	4,000,000	3,000,000
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Amount	-2,000,000	0	-2,000,000	0
Investment Tax Credit Basis Adjustment	0	-11,000,000	0	-11,039,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	0	-1,000,000	1,000,000	-1,000,000
Income Tax Expense	24,837,000	3,675,000	34,505,000	11,033,000
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Income Taxes [Line Items]	'	'	'	'
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	22,000,000	12,000,000	27,000,000	12,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	3,000,000	2,000,000	3,000,000	2,000,000
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Amount	-2,000,000	0	'	'
Investment Tax Credit Basis Adjustment	0	-11,000,000	0	-10,751,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	0	-1,000,000	0	0
Income Tax Expense	$22,742,000	$1,652,000	$28,080,000	$2,909,000

RECLASSIFICATIONS_FROM_ACCUMUL2

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT Reclassifications From Accumulated Other Comprehensive Income By Component) (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Tax Benefit	$430	$451	$734	$820
Realized Losses on Cash Flow Hedges, Net of Taxes	-664	-690	-1,309	-1,255
Amortization of SERP and Defined Benefit Plans	'	'	'	'
Prior Service Costs	-40	-111	-79	-222
Tax Benefit	15	43	30	85
Amortization, Net of Taxes	-25	-68	-49	-137
Total Reclassification from Other Comprehensive Income for the Period	-689	-758	-1,358	-1,392
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Tax Benefit	408	429	692	781
Realized Losses on Cash Flow Hedges, Net of Taxes	-630	-659	-1,240	-1,193
Amortization of SERP and Defined Benefit Plans	'	'	'	'
Prior Service Costs	-40	-111	-79	-222
Tax Benefit	15	43	30	85
Amortization, Net of Taxes	-25	-68	-49	-137
Total Reclassification from Other Comprehensive Income for the Period	-655	-727	-1,289	-1,330
Interest Rate Contract Long Term Debt [Member]	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), realized Gain (Loss) on Derivatives Arising During Period, before Tax	-349	-346	-702	-676
Interest Rate Contract Long Term Debt [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), realized Gain (Loss) on Derivatives Arising During Period, before Tax	-293	-293	-591	-575
Interest Rate contract Capital Leases [Member]	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), realized Gain (Loss) on Derivatives Arising During Period, before Tax	-602	-604	-1,198	-1,208
Interest Rate contract Capital Leases [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), realized Gain (Loss) on Derivatives Arising During Period, before Tax	-602	-604	-1,198	-1,208
Commodity Contract [Member]	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), realized Gain (Loss) on Derivatives Arising During Period, before Tax	-143	-191	-143	-191
Commodity Contract [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), realized Gain (Loss) on Derivatives Arising During Period, before Tax	($143)	($191)	($143)	($191)