Tucson Electric Power 10-Q 7 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 25, 2013
Entity Information [Line Items]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'UNS	'
Entity Registrant Name	'UNS Energy Corp	'
Entity Central Index Key	'0000941138	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	41,537,582
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 Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	32,139,434

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues	'	'	'	'
Electric Domestic Regulated Revenue	$362,244	$353,473	$868,523	$850,975
Sales Revenue from Energy Commodities and Services	27,529	29,341	92,581	88,469
Gas Retail Sales	15,430	15,407	86,432	85,621
Other Revenue, Net	31,838	35,887	86,863	88,427
Revenues	437,041	434,108	1,134,399	1,113,492
Operating Expenses	'	'	'	'
Utilities Operating Expense, Fuel Used	85,102	92,873	253,249	245,933
Utilities Operating Expense, Purchased Power	67,429	57,085	189,384	165,078
Cost of Transmission	8,061	4,500	15,768	10,738
Increase (Decrease) to Reflect PPFAC Recovery	-3,521	18,076	-6,814	29,730
Cost of Goods and Services, Energy Commodities and Services	157,071	172,534	451,587	451,479
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses	93,202	98,346	278,245	283,587
Cost of Services, Depreciation	38,204	35,145	111,175	105,319
Amortization of Deferred Charges	5,193	9,069	21,600	26,845
Taxes, Miscellaneous	13,606	12,605	41,329	37,385
Operating Expenses	307,276	327,699	903,936	904,615
Operating Income (Loss)	129,765	106,409	230,463	208,877
Other Income (Deductions)	'	'	'	'
Investment Income, Interest	2	340	31	981
Other Nonoperating Income	2,044	1,011	5,545	3,855
Other Nonoperating Expense	-438	-752	-1,817	-1,508
Life Insurance, Corporate or Bank Owned, Change in Value	731	581	1,864	1,621
Nonoperating Income (Expense)	2,339	1,180	5,623	4,949
Interest and Debt Expense [Abstract]	'	'	'	'
Interest Expense, Debt	17,580	17,074	53,534	53,811
Interest Expense, Lessee, Assets under Capital Lease	6,323	8,507	18,821	25,105
Interest Expense, Other	230	692	183	1,712
Interest Costs Capitalized	-933	-459	-2,352	-1,646
Interest Expense	23,200	25,814	70,186	78,982
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	108,904	81,775	165,900	134,844
Income Tax Expense (Benefit)	40,914	31,111	51,947	51,430
Net Income	67,990	50,664	113,953	83,414
Weighted-Average Shares of Common Stock Outstanding (000)	'	'	'	'
Basic	41,650	41,446	41,596	39,983
Diluted	42,028	41,863	41,941	41,719
Earnings Per Share	'	'	'	'
Basic	$1.63	$1.22	$2.74	$2.09
Diluted	$1.62	$1.21	$2.72	$2.03
Dividends Declared Per Share	$0.44	$0.43	$1.30	$1.29
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Operating Revenues	'	'	'	'
Electric Domestic Regulated Revenue	310,632	302,893	739,147	716,993
Sales Revenue from Energy Commodities and Services	26,563	25,448	90,503	77,488
Other Revenue, Net	34,044	38,569	93,603	95,826
Revenues	371,239	366,910	923,253	890,307
Operating Expenses	'	'	'	'
Utilities Operating Expense, Fuel Used	82,065	88,402	247,417	237,930
Utilities Operating Expense, Purchased Power	42,477	27,576	89,815	62,064
Cost of Transmission	4,940	1,914	7,535	4,277
Increase (Decrease) to Reflect PPFAC Recovery	-7,992	20,025	-5,079	25,150
Cost of Goods and Services, Energy Commodities and Services	121,490	137,917	339,688	329,421
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses	79,335	86,942	239,170	248,092
Cost of Services, Depreciation	30,311	27,644	87,729	82,656
Amortization of Deferred Charges	6,118	10,001	24,393	29,621
Taxes, Miscellaneous	10,808	10,327	32,916	30,325
Operating Expenses	248,062	272,831	723,896	720,115
Operating Income (Loss)	123,177	94,079	199,357	170,192
Other Income (Deductions)	'	'	'	'
Investment Income, Interest	6	28	14	97
Other Nonoperating Income	1,466	952	3,904	3,041
Other Nonoperating Expense	-2,776	-1,945	-7,493	-4,886
Life Insurance, Corporate or Bank Owned, Change in Value	731	581	1,864	1,621
Nonoperating Income (Expense)	-573	-384	-1,711	-127
Interest and Debt Expense [Abstract]	'	'	'	'
Interest Expense, Debt	13,848	13,268	42,412	40,562
Interest Expense, Lessee, Assets under Capital Lease	6,323	8,507	18,821	25,105
Interest Expense, Other	82	562	-86	1,338
Interest Costs Capitalized	-644	-361	-1,671	-1,381
Interest Expense	19,609	21,976	59,476	65,624
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	102,995	71,719	138,170	104,441
Income Tax Expense (Benefit)	38,828	27,150	41,737	39,423
Net Income	64,167	44,569	96,433	65,018
Retained Earnings [Member]	'	'	'	'
Interest and Debt Expense [Abstract]	'	'	'	'
Net Income	'	'	113,953	'
Retained Earnings [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Interest and Debt Expense [Abstract]	'	'	'	'
Net Income	'	'	$96,433	'

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income	$67,990	$50,664	$113,953	$83,414
Other Comprehensive Income (Loss)	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	685	370	2,229	641
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax	68	55	205	219
Other Comprehensive Income (Loss), Net of Tax	753	425	2,434	860
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	68,743	51,089	116,387	84,274
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Net Income	64,167	44,569	96,433	65,018
Other Comprehensive Income (Loss)	'	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	700	465	2,156	891
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax	68	55	205	219
Other Comprehensive Income (Loss), Net of Tax	768	520	2,361	1,110
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$64,935	$45,089	$98,794	$66,128

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	($448)	($244)	($1,459)	($421)
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	-42	-34	-127	-50
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	-458	-304	-1,412	-584
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	($42)	($34)	($127)	($50)

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash Flows from Operating Activities	'	'
Cash Receipts From Electric Retail Sales	$912,098	$894,195
Cash Receipts From Electric Wholesale Sales	118,341	107,854
Cash Receipts from Gas Retail Sales	109,994	114,055
Cash Receipts From Operating Spv Units Three And Four	75,552	75,715
Cash Receipts From Gas Wholesale Sales	3,558	565
Proceeds from Interest Received	516	2,884
Proceeds from Income Tax Refunds	0	307
Proceeds from Other Operating Activities	23,514	18,810
Fuel Costs Paid	-218,712	-239,397
Purchased Energy Costs Paid	-217,522	-189,927
Payment Of Operations And Maintenance Costs	-199,939	-207,780
Payments for Other Taxes	-124,782	-128,513
Payments to Employees	-96,899	-94,815
Interest Paid, Net	-50,108	-52,593
Capital Lease Interest Paid	-21,698	-27,895
Income Taxes Paid	-316	0
Payments for Other Operating Activities	-8,563	-5,327
Net Cash Provided by (Used in) Operating Activities	305,034	268,138
Cash Flows from Investing Activities	'	'
Payments to Acquire Property, Plant, and Equipment	-238,463	-232,036
Payments to Acquire Intangible Assets	-20,429	-7,554
Deposit—San Juan Mine Reclamation Trust	0	-1,107
Payments for (Proceeds from) Other Investing Activities	0	-232
Proceeds from Maturities, Prepayments and Calls of Held-to-maturity Securities	9,104	19,278
Restricted Cash Released	4,500	0
Proceeds from Note Receivable	0	12,500
Proceeds from Insurance Settlement, Investing Activities	0	2,875
Other Cash Receipts Investing Activities	6,625	14,484
Net Cash Provided by (Used in) Investing Activities	-238,663	-191,792
Cash Flows from Financing Activities	'	'
Proceeds from Lines of Credit	130,000	342,000
Repayments of Lines of Credit	-100,000	-346,000
Repayments of Long-term Capital Lease Obligations	-99,621	-89,452
Common Stock Dividends Paid	-54,146	-51,852
Proceeds from Issuance of Long-Term Debt	0	149,513
Repayments of Long-term Debt	0	-9,341
Payments of Financing Costs	-1,022	-3,349
Proceeds from Stock Options Exercised	2,724	3,529
Proceeds from Common Stock Issuance	408	0
Proceeds from (Payments for) Other Financing Activities	4,721	2,935
Other Cash Payments Financing Activities	-962	-718
Net Cash Provided by (Used in) Financing Activities	-117,898	-2,735
Cash and Cash Equivalents, Period Increase (Decrease)	-51,527	73,611
Cash and Cash Equivalents, Beginning of Period	123,918	76,390
Cash and Cash Equivalents, End of Period	72,391	150,001
TUCSON ELECTRIC POWER COMPANY	'	'
Cash Flows from Operating Activities	'	'
Cash Receipts From Electric Retail Sales	769,433	748,936
Cash Receipts From Electric Wholesale Sales	107,997	89,902
Cash Receipts From Operating Spv Units Three And Four	75,552	75,715
Cash Receipts From Gas Wholesale Sales	3,209	153
Reimbursement Of Affiliate Charges	17,639	16,783
Proceeds from Interest Received	509	2,014
Proceeds from Income Tax Refunds	77	200
Proceeds from Other Operating Activities	18,240	14,528
Fuel Costs Paid	-214,722	-233,457
Payment Of Operations And Maintenance Costs	-193,290	-200,569
Payments for Other Taxes	-97,419	-99,249
Payments to Employees	-80,964	-77,820
Purchased Power Costs Paid	-87,110	-60,684
Interest Paid, Net	-36,671	-35,728
Capital Lease Interest Paid	-21,698	-27,893
Income Taxes Paid	0	-1,796
Payments for Other Operating Activities	-6,603	-3,884
Net Cash Provided by (Used in) Operating Activities	254,179	207,151
Cash Flows from Investing Activities	'	'
Payments to Acquire Property, Plant, and Equipment	-180,451	-196,429
Payments to Acquire Intangible Assets	-17,552	-6,436
Deposit—San Juan Mine Reclamation Trust	0	-1,107
Proceeds from Maturities, Prepayments and Calls of Held-to-maturity Securities	9,104	19,278
Restricted Cash Released	4,500	0
Proceeds from Insurance Settlement, Investing Activities	0	2,875
Other Cash Receipts Investing Activities	4,656	9,207
Net Cash Provided by (Used in) Investing Activities	-179,743	-172,612
Cash Flows from Financing Activities	'	'
Proceeds from Lines of Credit	78,000	189,000
Repayments of Lines of Credit	-78,000	-199,000
Repayments of Long-term Capital Lease Obligations	-99,621	-89,452
Cash Dividends Paid to Parent Company	-20,000	0
Proceeds from Issuance of Long-Term Debt	0	149,513
Repayments of Long-term Debt	0	-6,535
Payments of Financing Costs	-1,022	-3,349
Proceeds from (Payments for) Other Financing Activities	1,976	1,292
Other Cash Payments Financing Activities	-726	-530
Net Cash Provided by (Used in) Financing Activities	-119,393	40,939
Cash and Cash Equivalents, Period Increase (Decrease)	-44,957	75,478
Cash and Cash Equivalents, Beginning of Period	79,743	27,718
Cash and Cash Equivalents, End of Period	$34,786	$103,196

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Utility Plant	'		'
Plant in Service	$5,114,426		$5,005,768
Utility Plant Under Capital Leases	621,247		582,669
Construction Work in Progress	211,100		128,621
Total Utility Plant	5,946,773		5,717,058
Less Accumulated Depreciation and Amortization	-1,966,801		-1,921,733
Less Accumulated Amortization of Capital Lease Assets	-509,712		-494,962
Total Utility Plant—Net	3,470,260		3,300,363
Investments And Other Property	'		'
Investments in Lease Equity	36,230		36,339
Other	33,441		36,537
Total Investments and Other Property	69,671		72,876
Current Assets	'		'
Cash and Cash Equivalents	72,391		123,918
Accounts Receivable—Customer	127,316		93,742
Unbilled Accounts Receivable	55,730		53,568
Allowance for Doubtful Accounts	-7,215		-6,545
Materials and Supplies	89,302		93,322
Fuel Inventory	44,458		62,019
Deferred Income Taxes—Current	66,520		34,260
Regulatory Assets—Current	52,709		51,619
Investments in Lease Debt	0		9,118
Derivative Instruments	1,620		3,165
Other	26,882		33,567
Total Current Assets	529,713		551,753
Regulatory and Other Assets	'		'
Regulatory Assets—Noncurrent	200,705	[1]	191,077	[1]
Derivative Instruments	752		3,801
Other Assets	22,704		20,559
Total Regulatory and Other Assets	224,161		215,437
Total Assets	4,293,805		4,140,429
Capitalization	'		'
Common Stock Equity	1,132,286		1,065,465
Capital Lease Obligations	130,088		262,138
Long-Term Debt	1,505,536		1,498,442
Total Capitalization	2,767,910		2,826,045
Current Liabilities	'		'
Current Obligations Under Capital Leases	169,060		90,583
Borrowings Under Revolving Credit Facilities	23,000		0
Accounts Payable—Trade	91,615		107,740
Accrued Taxes Other than Income Taxes	60,657		41,939
Interest Accrued	22,343		31,950
Accrued Employee Expenses	26,000		24,094
Regulatory Liabilities—Current	56,987	[2]	43,516	[2]
Customer Deposits	30,564		34,048
Derivative Instruments	12,988		14,742
Other	14,521		10,517
Total Current Liabilities	507,735		399,129
Liabilities, Noncurrent [Abstract]	'		'
Deferred Tax Liabilities, Net, Noncurrent	482,516		364,756
Regulatory Liability, Noncurrent	297,699	[3]	279,111	[3]
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	141,997		159,401
Derivative Liability, Noncurrent	7,183		12,709
Other Liabilities, Noncurrent	88,765		99,278
Liabilities, Noncurrent	1,018,160		915,255
Commitments and Contingencies	'		'
Total Capitalization and Other Liabilities	4,293,805		4,140,429
TUCSON ELECTRIC POWER COMPANY	'		'
Utility Plant	'		'
Plant in Service	4,434,770		4,348,041
Utility Plant Under Capital Leases	621,247		582,669
Construction Work in Progress	153,258		98,460
Total Utility Plant	5,209,275		5,029,170
Less Accumulated Depreciation and Amortization	-1,811,806		-1,783,787
Less Accumulated Amortization of Capital Lease Assets	-509,712		-494,962
Total Utility Plant—Net	2,887,757		2,750,421
Investments And Other Property	'		'
Investments in Lease Equity	36,230		36,339
Other	32,009		35,091
Total Investments and Other Property	68,239		71,430
Current Assets	'		'
Cash and Cash Equivalents	34,786		79,743
Accounts Receivable—Customer	105,646		71,813
Unbilled Accounts Receivable	46,240		33,782
Allowance for Doubtful Accounts	-5,238		-4,598
Accounts Receivable, Related Parties, Current	3,963		5,720
Materials and Supplies	76,255		80,377
Fuel Inventory	44,162		61,737
Deferred Income Taxes—Current	69,985		37,212
Regulatory Assets—Current	36,283		34,345	[1]
Investments in Lease Debt	0		9,118
Derivative Instruments	1,047		2,230
Other	20,605		32,163
Total Current Assets	433,734		443,642
Regulatory and Other Assets	'		'
Regulatory Assets—Noncurrent	186,626	[1]	178,330	[1]
Derivative Instruments	259		1,354
Other Assets	17,525		15,869
Total Regulatory and Other Assets	204,410		195,553
Total Assets	3,594,140		3,461,046
Capitalization	'		'
Common Stock Equity	939,721		860,927
Capital Lease Obligations	130,088		262,138
Long-Term Debt	1,223,536		1,223,442
Total Capitalization	2,293,345		2,346,507
Current Liabilities	'		'
Current Obligations Under Capital Leases	169,060		90,583
Accounts Payable—Trade	75,834		82,122
Accounts Payable—Due to Affiliates	2,981		3,134
Accrued Taxes Other than Income Taxes	50,465		33,060
Interest Accrued	20,503		26,965
Accrued Employee Expenses	22,937		20,715
Regulatory Liabilities—Current	26,440	[2]	20,822	[2]
Customer Deposits	21,251		24,846
Derivative Instruments	7,060		4,899
Other	9,336		7,085
Total Current Liabilities	405,867		314,231
Liabilities, Noncurrent [Abstract]	'		'
Deferred Tax Liabilities, Net, Noncurrent	421,621		319,216
Regulatory Liability, Noncurrent	259,523	[3]	241,189	[3]
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	132,491		149,718
Derivative Liability, Noncurrent	4,950		10,565
Other Liabilities, Noncurrent	76,343		79,620
Liabilities, Noncurrent	894,928		800,308
Commitments and Contingencies	'		'
Total Capitalization and Other Liabilities	$3,594,140		$3,461,046
[1]	Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment. See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.
[2]	Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.
[3]	Regulatory Liabilities – Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

CONDENSED_CONSOLIDATED_STATEME4

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	TUCSON ELECTRIC POWER COMPANY	Common Shares Outstanding [Member]	Common Stock [Member]	Common Stock [Member]	Capital Stock Expense [Member]	Accumulated Earnings/(Deficit) [Member]	Accumulated Earnings/(Deficit) [Member]	Accumulated Other Comprehensive Loss [Member]	Accumulated Other Comprehensive Loss [Member]
In Thousands, unless otherwise specified	USD ($)	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, 2012	$1,065,465	$860,927	'	$882,138	$888,971	($6,357)	$193,117	($12,157)	($9,790)	($9,530)
Balances, shares at Dec. 31, 2012	'	'	41,344	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	113,953	96,433	'	'	'	'	113,953	96,433	'	'
Other Comprehensive Income (Loss), Net of Tax	2,434	2,361	'	'	'	'	'	'	2,434	2,361
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	116,387	98,794	'	'	'	'	'	'	'	'
Dividends, Including Non-Cash Dividend Equivalents	-54,733	'	'	'	'	'	-54,733	'	'	'
Stock Issued During Period, Shares, Dividend Reinvestment Plan	'	'	9	'	'	'	'	'	'	'
Stock Issued During Period, Value, Dividend Reinvestment Plan	408	'	'	408	'	'	'	'	'	'
Shares Issued for Stock Options	2,724	'	'	2,724	'	'	'	'	'	'
Shares Issued for Stock Options, shares	'	'	85	'	'	'	'	'	'	'
Shares Issued Under Performance Share Awards	0	'	'	0	'	'	'	'	'	'
Shares Issued Under Performance Share Awards, shares	'	'	57	'	'	'	'	'	'	'
Other	2,035	'	'	2,035	'	'	'	'	'	'
Payments of Dividends	'	-20,000	'	'	'	'	'	-20,000	'	'
Balances at Sep. 30, 2013	1,132,286	939,721	'	887,305	888,971	-6,357	252,337	64,276	-7,356	-7,169
Balances, shares at Sep. 30, 2013	'	'	41,495	'	'	'	'	'	'	'
Balances at Jun. 30, 2013	'	'	'	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	67,990	64,167	'	'	'	'	'	'	'	'
Other Comprehensive Income (Loss), Net of Tax	753	768	'	'	'	'	'	'	'	'
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	68,743	64,935	'	'	'	'	'	'	'	'
Balances at Sep. 30, 2013	$1,132,286	$939,721	'	'	$888,971	($6,357)	'	'	'	'

CONDENSED_CONSOLIDATED_STATEME5

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (Parenthetical) (USD $)	9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013
Common Stock, Shares Authorized	75,000,000
Tax effect of Other Comprehensive Income	($1,586)
TUCSON ELECTRIC POWER COMPANY	'
Tax effect of Other Comprehensive Income	($1,539)

FINANCIAL_STATEMENT_PRESENTATI

FINANCIAL STATEMENT PRESENTATION	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
FINANCIAL STATEMENT PRESENTATION	'
	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 Gas, Inc. (UNS Gas); and UNS Electric, Inc. (UNS Electric). 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 2012 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 UNS ENERGY INCOME STATEMENT
	During the first three quarters of 2012, we incorrectly reported UNS Electric's sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $3 million for the three months ended and $10 million for the nine months ended September 30, 2012. This error had no impact on operating income, net income, accumulated earnings, or cash flows.
	We assessed the impact of this error on prior period financial statements and concluded it was not material to any period. However, this error was significant to individual income statement line items. As a result, in accordance with GAAP, we revised our prior period income statement as follows:
		UNS Energy
		Three Months Ended				Nine Months Ended
		September 30, 2012				September 30, 2012
		As Reported		As Revised		As Reported		As Revised
		Thousands of Dollars				Thousands of Dollars
	Income Statement
	Electric Wholesale Sales	$	32,494	$	29,341	$	98,282	$	88,469
	Purchased Energy	60,238		57,085		174,891		165,078
	Total Fuel and Purchased Energy	175,687		172,534		461,292		451,479
	Total Operating Expenses	330,852		327,699		914,428		904,615
	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
	In 2013, we adopted authoritative guidance that:
	•	Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 11.
	•	Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 12.
	•	Allows an entity to perform a qualitative analysis to determine if additional testing for impairment of indefinite-lived intangible assets is required. Based on our qualitative analysis, we had no impairment indicator as our only indefinite-lived intangible assets, Renewable Energy Credits (RECs), are currently recoverable under the Renewable Energy Standard (RES) as we use the RECs to comply with the standard’s renewable resources requirements.

REGULATORY_MATTERS

REGULATORY MATTERS

9 Months Ended

Sep. 30, 2013

Text Block [Abstract]

'

REGULATORY MATTERS

'

REGULATORY MATTERS

RATES AND REGULATION

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP, UNS Gas, and UNS Electric. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, and transactions with affiliated parties. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

2013 TEP RATE ORDER

In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012 which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

The provisions of the 2013 TEP Rate Order include, but are not limited to:

•

an increase in non-fuel retail Base Rates of approximately $76 million over adjusted test year revenues;

•

an Original Cost Rate Base (OCRB) of approximately $1.5 billion and a Fair Value Rate Base (FVRB) of approximately $2.3 billion;

•

a return on equity of 10.0%, a long-term cost of debt of 5.18%, and a short-term cost of debt of 1.42%, resulting in a weighted average cost of capital of 7.26%;

•

a capital structure of approximately 43.5% equity, 56.0% long-term debt, and 0.5% short-term debt;

•

a 0.68% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million);

•

a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11 million annually; and

•

an agreement by TEP to seek recovery of costs related to the Nogales transmission line from the FERC before seeking rate recovery from the ACC.

The 2013 TEP Rate Order also includes the following cost recovery mechanisms:

•

a new Purchased Power and Fuel Adjustment Clause (PPFAC) credit of $0.001388 per kWh effective July 1, 2013. The credit reflects the following:

◦

a one-time reduction in the PPFAC bank balance, recorded in June 2013 as an increase to fuel expense, of $3 million related to prior Sulfur Credits; and

◦

a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory asset to defer coal costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final insurance settlement.

•

a modification of the PPFAC mechanism to include recovery of generation-related lime costs offset by Sulfur Credits.

•

a Lost Fixed Cost Recovery mechanism (LFCR) to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation, subject to ACC approval and a year-over-year cap of 1% of TEP's total retail revenues. TEP expects the LFCR rate, recovering 2013 costs, to be effective on July 1, 2014, upon approval of verified lost kWh sales by the ACC.

•

an Environmental Compliance Adjustor (ECA) mechanism to recover certain capital carrying costs to comply with government-mandated environmental regulations between rate cases. The ECA rate is capped at $0.00025 per kWh, which approximates 0.25% of TEP's total retail revenues, and will be charged to customers beginning in May 2014 for any qualifying costs incurred between August 2013 and December 2013.

•

an energy efficiency provision which includes a 2013 calendar year budget to fund programs that support the ACC's Electric Energy Efficiency Standards, as well as a performance incentive.

PENDING UNS ELECTRIC RATE CASE

In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric's 2010 Rate Order. UNS Electric's rate filing was based on a test year ended June 30, 2012.

In September 2013, UNS Electric, the staff of the ACC, and certain other parties to UNS Electric's pending rate case proceeding entered into a settlement agreement (2013 UNS Electric Settlement Agreement). The 2013 UNS Electric Settlement Agreement requires the approval of the ACC before new rates can become effective.

The terms of the 2013 UNS Electric Settlement Agreement include, but are not limited to:

•

an increase in non-fuel retail Base Rates of approximately $3 million;

•

an OCRB of approximately $213 million and a FVRB of approximately $283 million;

•

a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;

•

a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and

•

a capital structure of 52.6% equity and 47.4% long-term debt.

The 2013 UNS Electric Settlement Agreement also includes the following cost recovery mechanisms:

•

an LFCR mechanism to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation; and

•

a Transmission Cost Adjustor (TCA). The TCA would allow more timely recovery of transmission costs associated with serving retail customers.

UNS GAS PURCHASED GAS ADJUSTOR

In October 2013, the ACC approved an increase to the existing Purchased Gas Adjustor (PGA) credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At September 30, 2013, the PGA bank balance was over-collected by $17 million on a billed-to-customer basis.

REGULATORY ASSETS AND LIABILITIES

The following table summarizes changes in regulatory assets and liabilities since December 31, 2012:

30-Sep-13

31-Dec-12

UNS

TEP

UNS

TEP

Energy

Energy

Millions of Dollars

Regulatory Assets – Current

$

53

$

36

$

52

$

34

Regulatory Assets – Noncurrent (1)

201

187

191

178

Regulatory Liabilities – Current (2)

(57

)

(26

)

(44

)

(21

)

Regulatory Liabilities – Noncurrent (3)

(298

)

(260

)

(279

)

(241

)

Total Net Regulatory Assets (Liabilities)

$

(101

)

$

(63

)

$

(80

)

$

(50

)

(1)

Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment. See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.

(2)

Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.

(3)

Regulatory Liabilities – Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF REGULATORY ACCOUNTING

If our regulated operations no longer met the requirements to apply regulatory accounting we would remove our regulatory assets and liabilities by:

•

writing off the remaining regulatory assets as an expense and regulatory liabilities as income in the income statements; and

•

reflecting regulatory pension assets as part of AOCI.

If we had stopped applying regulatory accounting at September 30, 2013:

•

TEP would have recorded an extraordinary after-tax gain of $113 million and an after-tax loss in AOCI of $75 million;

•

UNS Gas would have recorded an extraordinary after-tax gain of $26 million and an after-tax loss in AOCI of $2 million; and

•

UNS Electric would have recorded an extraordinary after-tax gain of $3 million and an after-tax loss in AOCI of $3 million.

While future regulatory orders and market conditions may affect cash flows, our cash flows would not be affected if we stopped applying regulatory accounting to our regulated operations.

BUSINESS_SEGMENTS

BUSINESS SEGMENTS	9 Months Ended
	Sep. 30, 2013
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 Gas, a regulated gas distribution utility
	-3	UNS Electric, a regulated electric utility
	We disclose selected financial data for our reportable segments in the following table:
		Reportable Segments
		TEP		UNS			UNS		Non-Reportable Segments			Reconciling			UNS
				Gas			Electric					Adjustments			Energy
															Consolidated
		Millions of Dollars
	Income Statement
	Three Months Ended September 30, 2013
	Operating Revenues – External	$	367	$	16		$	54	$	—		$	—		$	437
	Operating Revenues – Intersegment(1)	4		2			—		4			(10		)	—
	Net Income	64		(1		)	5		—			—			68
	Three Months Ended September 30, 2012
	Operating Revenues – External	$	362	$	16		$	56	$	—		$	—		$	434
	Operating Revenues – Intersegment(1)	5		2			—		5			(12		)	—
	Net Income	45		—			6		—			—			51
		Reportable Segments
		TEP		UNS			UNS		Non-Reportable Segments			Reconciling			UNS
				Gas			Electric					Adjustments			Energy
															Consolidated
		Millions of Dollars
	Income Statement
	Nine Months Ended September 30, 2013
	Operating Revenues – External	$	910	$	90		$	134	$	—		$	—		$	1,134
	Operating Revenues – Intersegment(1)	13		3			1		12			(29		)	—
	Net Income	96		6			11		1			—			114
	Nine Months Ended September 30, 2012
	Operating Revenues – External	$	877	$	89		$	147	$	—		$	—		$	1,113
	Operating Revenues – Intersegment(1)	13		4			1		14			(32		)	—
	Net Income	65		5			14		(1		)	—			83
	(1)	Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

9 Months Ended

Sep. 30, 2013

Text Block [Abstract]

'

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

'

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

In addition those reported in our 2012 Annual Report on Form 10-K, we entered into the following new long-term commitments through September 30, 2013:

TEP COMMITMENTS

Purchase Commitments

2013

2014

2015

2016

2017

Thereafter

Total

Millions of Dollars

Purchased Power, Including Renewable PPA(1)

$

2

$

18

$

6

$

4

$

4

$

58

$

92

Capital Lease Obligations(2)

—

—

46

—

—

—

46

RES Performance-Based Incentives(3)

1

1

1

1

1

7

12

Fuel Transportation(4)

4

5

5

5

5

1

25

Total Purchase Commitments

$

7

$

24

$

58

$

10

$

10

$

66

$

175

-1

Purchased Power costs are recoverable from customers through the PPFAC. A portion of the Renewable Power Purchase Agreement (PPA) is recoverable through the PPFAC, with the balance recoverable through the RES tariff.

-2

In the third and fourth quarters of 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 5.

-3

The RES Performance-Based Incentive (PBI) costs are recoverable through the RES tariff.

-4

Fuel Transportation costs are recoverable from customers through the PPFAC.

UNS GAS COMMITMENTS

Forward Energy Contracts

UNS Gas entered into new forward energy commitments that settle through 2016 at fixed prices per million British thermal units (MMBtu). UNS Gas’ minimum payment obligations for these purchases are $2 million in 2014, $3 million in 2015, and $2 million in 2016.

Fuel Transportation

UNS Gas entered into revised gas transportation agreements in August 2013. UNS Gas anticipates that its commitments will increase by $3 million in 2013, $9 million each year in 2014 through 2016, $10 million in 2017, and $56 million thereafter.

UNS ELECTRIC COMMITMENTS

Purchased Power Contracts

UNS Electric entered into new forward purchased power commitments that will settle through 2015 at fixed prices per MWh. UNS Electric’s minimum payment obligations for these purchases are $1 million in 2014 and $4 million in 2015.

TEP CONTINGENCIES

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. All parties filed a joint motion to stay until December 1, 2013.

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. The coal supplier and Four Corners’ operating agent intend to contest the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. TEP cannot predict the 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 is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) recorded was $18 million at September 30, 2013 and $16 million at December 31, 2012.

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 on an accrual basis and recovering the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric expect to abandon the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the 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. 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. See Note 2. In 2012, TEP recorded a regulatory asset of $5 million and UNS Electric recorded a regulatory asset of $0.2 million for the balance deemed probable of recovery.

RESOLUTION OF TEP CONTINGENCIES

Springerville Generating Station Unit 3 Outage

TEP paid Tri-State Generating and Transmission Association, Inc. (Tri-State) $2 million in March 2013 as a result of an outage at Springerville Unit 3 in 2012. TEP accrued the pre-tax loss in July 2012 as a result of not meeting certain availability requirements under the terms of TEP's operating agreement with Tri-State.

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

The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules to set the standards for the control of mercury emissions and other hazardous air pollutants from power plants.

Navajo

Based on the EPA’s standards, Navajo may require mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which will be affected by final Best Available Retrofit Technology (BART) rules when issued. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each.

San Juan

TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards.

Four Corners

Based on the EPA’s final standards, Four Corners may require mercury emission control equipment by 2015. TEP's share of the estimated capital cost of this equipment is less than $1 million. TEP expects its share of the annual operating cost of the mercury emission control equipment to be less than $1 million.

Springerville Generating Station

Based on the EPA’s final standards, Springerville Generating Station (Springerville) may require mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million.

Sundt Generating Station

TEP expects the final EPA standards will have little effect on capital expenditures at Sundt Generating Station (Sundt).

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. 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.

Complying with the EPA’s BART findings, 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. TEP cannot predict the ultimate outcome of these matters.

Navajo

In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, submitted an agreement to the EPA that would achieve greater NOx emission reductions than the EPA's proposed BART rule. In September 2013, EPA issued a supplemental proposal incorporating the provisions of the agreement as a better-than-BART alternative.

Among other things, the agreement calls for the shut down of one unit or an equivalent reduction in emissions by 2020. The shutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install SCR or an equivalent technology on the remaining two units by 2030. As part of the agreement, the current owners have committed to cease their operation of conventional coal-fired generation at Navajo no later than December 2044. The Navajo Nation can continue operation after 2044 at its election. If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.

San Juan

In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.

In 2011, Public Service Company of New Mexico (PNM) filed a petition for review of, and a motion to stay, the FIP with the United States Court of Appeals for the Tenth Circuit (Tenth Circuit). In addition, the operator filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA's reconsideration and review by the Tenth Circuit. The State of New Mexico filed similar motions with the Tenth Circuit and the EPA. Several environmental groups were granted permission to join in opposition to PNM's petition to review in the Tenth Circuit. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP's five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Tenth Circuit denied PNM's and the State of New Mexico's motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the court's decision. In February 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals.

In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement that outlines an alternative to the FIP. The terms of the agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of Selective Non-Catalytic Reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. The New Mexico Environmental Department (NMED) prepared a revision to the regional haze SIP incorporating the provisions of the agreement, and in September 2013, the New Mexico Environmental Improvement Board approved the SIP revision. The SIP revision now awaits final EPA approval.

TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $35 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At September 30, 2013, the book value of TEP's share of San Juan Unit 2 was $114 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. TEP cannot predict the ultimate outcome of this matter.

Four Corners

In August 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly-owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. APS must select which FIP alternative to implement by December 31, 2013. In either case, TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $35 million. TEP's share of incremental annual operating costs for SCR is estimated at $2 million.

Springerville

The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville. Other provisions of the Regional Haze Rule requiring further emission reduction are not likely to impact Springerville operations until after 2018.

Sundt

In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule. Under the Regional Haze Rule, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART determination. The EPA postponed its expected release of a proposed BART requirement for Sundt Unit 4 until December 2013, with a final determination expected in May 2014. While TEP does not agree that Sundt Unit 4 is BART eligible, in anticipation of EPA's proposed BART requirements, TEP has submitted a plan for EPA approval proposing to eliminate coal as a fuel after December 2017.

Greenhouse Gas Regulation

In June 2013, President Obama directed the EPA to move forward with carbon emission regulations for both new and existing fossil-fueled power plants.

In September 2013, the EPA issued a re-proposed rule for new power plants. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

For existing power plants, the President ordered the EPA to:

•

propose carbon emission standards by June 1, 2014;

•

finalize those standards by June 1, 2015; and

•

require states to submit their implementation plans to meet the standards by June 30, 2016.

UNS Energy will continue to work with federal and state regulatory agencies to promote compliance flexibility in the rules impacting existing fossil-fuel fired power plants. We cannot predict the ultimate outcome of these matters.

DEBT_CREDIT_FACILITIES_AND_CAP

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	'
	DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS
	We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2012 Annual Report on Form 10-K.
	TEP SPRINGERVILLE UNIT 1 CAPITAL LEASE PURCHASE COMMITMENTS
	In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a continuous capacity rating of 387 MW. The appraisal price was challenged, and TEP initiated a proceeding in 2012 seeking judicial confirmation of the results of the appraisal process.
	In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregate purchase price of $46 million, the appraised value, upon the expiration of the lease term in January 2015.
	In October 2013, TEP elected to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of continuous operating capability, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014.
	Upon close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of continuous operating capability. Due to TEP's purchase commitment, TEP and UNS Energy expect to record an increase of approximately $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets, of which $39 million is reflected as of September 30, 2013.
	Because the owner participants whose leased interests TEP elected to purchase have agreed to sell their interests for amounts equal to the appraised value, TEP dismissed the legal action associated with the appraisal.
	TEP TAX-EXEMPT BONDS ISSUED
	In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 1, 2023. The proceeds from the sale of the bonds, together with $0.5 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received nor disbursed by TEP. TEP capitalized approximately $1 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statement through September 2029, the term of the bonds.
	UNS ENERGY'S AND TEP'S CREDIT RATING UPGRADES
	In June 2013, the pricing under certain debt agreements improved as a result of an upgrade in the credit ratings of UNS Energy and TEP.
	•	Under the UNS Energy Credit Agreement, the interest rate decreased from London Interbank Offered Rate (LIBOR) plus 1.75% to LIBOR plus 1.5%;
	•	Under the TEP Credit Agreement, the interest rate decreased from LIBOR plus 1.125% to LIBOR plus 1.0% ; and the margin rate on the $186 million letter of credit facility decreased from 1.125% to 1.0% ; and
	•	Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit decreased from 1.5% to 1.25% per annum.
	TEP MORTGAGE INDENTURE
	Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP (i) requested $423 million in mortgage bonds be returned to TEP for cancellation, and (ii) discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured, which changed the pricing of the following agreements, with pricing tied to credit ratings for short-term borrowings:
	•	Under the TEP Credit Agreement, the interest rate increased from LIBOR plus 1.0% to LIBOR plus 1.25%; and the margin rate on the $186 million letter of credit facility increased from 1.0% to 1.25%; and
	•	Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit increased from 1.25% to 1.75% per annum.
	COVENANT COMPLIANCE
	At September 30, 2013, we were in compliance with the terms of our credit agreements, the 2010 TEP Reimbursement Agreement, and UNS Electric's term loan.

INCOME_TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
INCOME TAXES	'
	INCOME TAXES
	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		UNS Energy						TEP
		Three Months Ended September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	38		$	29		$	36		$	25
	State Income Tax Expense, Net of Federal Deduction	5			3			5			3
	Federal/State Tax Credits	(1		)	(1		)	(1		)	(1		)
	Other	(1		)	—			(1		)	—
	Total Federal and State Income Tax Expense	41			$	31		$	39		$	27
		UNS Energy						TEP
		Nine Months Ended September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	58		$	47		$	48		$	37
	State Income Tax Expense, Net of Federal Deduction	8			6			6			4
	Federal/State Tax Credits	(2		)	(1		)	(2		)	(1		)
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—			(11		)	—
	Other	(1		)	(1		)	1			(1		)
	Total Federal and State Income Tax Expense	$	52		$	51		$	42		$	39
	Investment Tax Credit Basis Difference Adjustment
	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.
	Uncertain Tax Positions
	We recognize tax benefits from uncertain tax positions if it is more likely than not that the tax position will be sustained on examination by the taxing authorities. Each uncertain tax position is recognized up to the amount most likely to be sustained on examination and adjusted with changes in facts and circumstances. A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
		UNS Energy			TEP
		Millions of Dollars
	Unrecognized Tax Benefits at December 31, 2012	$	30		$	23
	Additions Based on Tax Positions Taken in the Current Year	1			1
	Reduction of Positions from Prior Year Based on Tax Authority Ruling	(27		)	(22		)
	Unrecognized Tax Benefits at September 30, 2013	$	4		$	2
	In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources.  These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation.  As a result of the IRS ruling in the first quarter of 2013, UNS Energy reduced unrecognized tax benefits by $28 million, and TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.
	The IRS completed its audit of the 2009 and 2010 tax returns in March 2013 resulting in no change to the financial statements.
	In April 2013, the IRS provided notice of intent to audit the 2011 tax returns.
	Tangible Repairs Regulation
	In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. Management believes that adoption of these regulations will not result in a material change to plant-related deferred tax liabilities.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	9 Months Ended
	Sep. 30, 2013
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 September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Service Cost	$	4		$	2		$	1		$	1
	Interest Cost	4			4			—			1
	Expected Return on Plan Assets	(5		)	(4		)	—			—
	Actuarial Loss Amortization	2			2			—			—
	Net Periodic Benefit Cost	$	5		$	4		$	1		$	2
		Pension Benefits						Other Retiree Benefits
		Nine Months Ended September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Service Cost	$	10		$	8		$	3		$	2
	Interest Cost	11			12			2			2
	Expected Return on Plan Assets	(15		)	(13		)	(1		)	—
	Actuarial Loss Amortization	7			5			—			—
	Net Periodic Benefit Cost	$	13		$	12		$	4		$	4

SHAREBASED_COMPENSATION_PLANS

SHARE-BASED COMPENSATION PLANS	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
SHARE-BASED COMPENSATION PLANS	'
	SHARE-BASED COMPENSATION PLANS
	RESTRICTED STOCK UNITS
	In May 2013, the UNS Energy Compensation Committee granted 8,870 restricted stock units to non-employee directors at a grant date fair value of $48.99 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. The grant date fair value was calculated by reducing the grant date share price by the present value of the dividends expected to be paid on the shares during the vesting period. Fully vested but undistributed non-employee director stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. We issue UNS Energy Common Stock (Common Stock) for the vested stock units in the January following the year the person is no longer a director.
	In February 2013, the UNS Energy Compensation Committee granted 21,560 restricted stock units to certain management employees at a grant date fair value, based on the grant date share price, of $46.23 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 2013, the UNS Energy Compensation Committee granted 43,120 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 $45.54 per share. Those awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Return to the companies included in the Edison Electric Institute Index during the performance period of January 1, 2013 through December 31, 2015. 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 share price, of $46.23 per share and will be paid out in Common Stock based on cumulative net income for the three-year period ended December 31, 2015. 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 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 $1 million of share-based compensation expense for the three months ended September 30, 2013 and September 30, 2012. For the nine months ended September 30, 2013, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. For the nine months ended September 30, 2012, UNS Energy and TEP recorded share-based compensation expense of $2 million.
	At September 30, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $4 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At September 30, 2013, 1 million shares were awarded but not yet issued, including performance shares, under the share-based compensation plans.

UNS_ENERGY_EARNINGS_PER_SHARE

UNS ENERGY EARNINGS PER SHARE	9 Months Ended
	Sep. 30, 2013
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, share-based compensation awards, or UNS Energy's Convertible Senior Notes were exercised or converted into Common Stock. We excluded anti-dilutive stock options and contingently issuable shares from the calculation of diluted EPS. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the remaining notes, not yet converted, were converted to Common Stock.
	The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:
		Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013		2012
		Thousands of Dollars
	Numerator:
	Net Income	$	67,990		$	50,664		$	113,953	$	83,414
	Income from Assumed Conversion of Convertible Senior Notes (1)	—			—			—		1,100
	Adjusted Net Income Available for Diluted Common Stock Outstanding	$	67,990		$	50,664		$	113,953	$	84,514
		Thousands of Shares
	Denominator:
	Weighted Average Shares of Common Stock Outstanding:
	Common Shares Issued	41,472			41,290			41,427		39,835
	Fully Vested Deferred Stock Units	178			156			169		148
	Total Weighted Average Common Stock Outstanding – Basic	41,650			41,446			41,596		39,983
	Effect of Dilutive Securities:
	Convertible Senior Notes (1)	—			—			—		1,417
	Options and Stock Issuable Under Share-Based Compensation Plans	378			417			345		319
	Total Weighted Average Common Stock Outstanding – Diluted	42,028			41,863			41,941		41,719
	(1) In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.
	We excluded the following outstanding stock options, with an exercise price above market, and contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive:
		Three Months Ended September 30,					Nine Months Ended September 30,
		2013		2012			2013		2012
		Thousands of Shares
	Stock Options	—		—			—		67
	Restricted Stock Units	—		—			8		—
	Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	—		—			8		67

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2013
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
		Nine Months Ended September 30,
		2013			2012
		Thousands of Dollars
	Net Income	$	113,953		$	83,414
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	111,175			105,319
	Amortization Expense	21,600			26,845
	Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	5,399			4,911
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,280			2,250
	Provision for Retail Customer Bad Debts	1,703			2,017
	Use of RECs for Compliance	12,999			4,017
	Deferred Income Taxes	77,962			63,057
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—
	Pension and Retiree Expense	17,087			16,391
	Pension and Retiree Funding	(27,602		)	(23,649		)
	Share-Based Compensation Expense	2,810			1,952
	Allowance for Equity Funds Used During Construction	(4,145		)	(2,708		)
	Increase (Decrease) to Reflect PPFAC/PGA Recovery	(6,814		)	29,730
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—
	Liquidated Damages for Springerville Unit 3 Outage	—			1,921
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(32,883		)	(28,686		)
	Materials and Fuel Inventory	14,839			(33,038		)
	Accounts Payable	(18,497		)	(5,220		)
	Income Taxes	(15,847		)	(11,738		)
	Interest Accrued	(2,137		)	(1,551		)
	Taxes Other Than Income Taxes	18,718			16,478
	Other	20,473			16,426
	Net Cash Flows – Operating Activities	$	305,034		$	268,138
		TEP
		Nine Months Ended September 30,
		2013			2012
		Thousands of Dollars
	Net Income	$	96,433		$	65,018
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	87,729			82,656
	Amortization Expense	24,393			29,621
	Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	4,602			3,922
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,831			1,628
	Provision for Retail Customer Bad Debts	1,315			1,348
	Use of RECs for Compliance	11,766			3,324
	Deferred Income Taxes	64,132			51,638
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—
	Pension and Retiree Expense	14,909			14,466
	Pension and Retiree Funding	(26,118		)	(20,989		)
	Share-Based Compensation Expense	2,239			1,540
	Allowance for Equity Funds Used During Construction	(2,923		)	(2,265		)
	Increase (Decrease) to Reflect PPFAC Recovery	(5,079		)	25,150
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—
	Liquidated Damages for Springerville Unit 3 Outage	—			1,921
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(42,542		)	(44,269		)
	Materials and Fuel Inventory	14,955			(32,448		)
	Accounts Payable	(8,678		)	4,977
	Income Taxes	(10,681		)	(11,424		)
	Interest Accrued	1,008			2,729
Taxes Other Than Income Taxes	17,405			16,710
Other	15,234			11,898
Net Cash Flows – Operating Activities	$	254,179		$	207,151
Non-Cash Transactions
In August 2013, TEP recorded an increase of $39 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in January 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. See Note 5.
In September 2012, TEP declared a $30 million dividend to UNS Energy which was paid in October 2012.
In the first nine months of 2012, UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Stock, resulting in non-cash transactions.
In the first nine months of 2012, TEP's redemption of $193 million of tax-exempt bonds resulted in a non-cash transaction.

FAIR_VALUE_MEASUREMENTS_DERIVA

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
FAIR VALUE MEASUREMENTS AND 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.
	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 assets, current liabilities, including 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 Debt, we calculated the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporated the impact of counterparty credit risk using market credit default swap data. TEP's Investment in Lease Debt matured in January 2013.
	•	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-Sep-13								31-Dec-12
		Fair Value		Carrying				Fair				Carrying				Fair
		Hierarchy		Value				Value				Value				Value
				Millions of Dollars
	Assets:
	TEP Investment in Lease Debt	Level 2		$	—			$	—			$	9			$	9
	TEP Investment in Lease Equity	Level 3		36				24				36				23
	Liabilities:
	Long-Term Debt
	UNS Energy	Level 2		1,506				1,522				1,498				1,583
	TEP	Level 2		1,224				1,215				1,223				1,271
	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-Sep-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	31			$	31			$	—			$	—			$	—		$	31
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	21				—				21				—				—			21
	Energy Contracts - Regulatory Recovery(3)	2				—				1				1				(2		)	—
	Total Assets	56				33				22				1				(2		)	54
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(11		)		—				(5		)		(6		)		2			(9		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(8		)		—				(8		)		—				—			(8		)
	Total Liabilities	(20		)		—				(13		)		(7		)		2			(18		)
	Net Total Assets (Liabilities)	$	36			$	33			$	9			$	(6	)		$	—		$	36
		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-12
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	20			$	20			$	—			$	—			$	—		$	20
	Restricted Cash(1)	7				7				—				—				—			7
	Rabbi Trust Investments(2)	19				—				19				—				—			19
	Energy Contracts - Regulatory Recovery(3)	7				—				2				5				(5		)	2
	Total Assets	53				27				21				5				(5		)	48
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(15		)		—				(7		)		(8		)		5			(10		)
	Energy Contracts - Cash Flow Hedge(3)	(2		)		—				—				(2		)		—			(2		)
	Interest Rate Swaps(4)	(10		)		—				(10		)		—				—			(10		)
	Total Liabilities	(27		)		—				(17		)		(10		)		5			(22		)
	Net Total Assets (Liabilities)	$	26			$	27			$	4			$	(5	)		$	—		$	26
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Sep-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	15			$	15			$	—			$	—			$	—		$	15
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	21				—				21				—				—			21
	Energy Contracts - Regulatory Recovery(3)	1				—				1				—				(1		)	—
Total Assets	39				17				22				—				(1		)	38
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)		—				(2		)		(1		)		1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
Interest Rate Swaps(4)	(8		)		—				(8		)		—				—			(8		)
Total Liabilities	(12		)		—				(10		)		(2		)		1			(11		)
Net Total Assets (Liabilities)	$	27			$	17			$	12			$	(2	)		$	—		$	27
	TEP
	Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	31-Dec-12
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1			$	1			$	—			$	—			$	—		$	1
Restricted Cash(1)	7				7				—				—				—			7
Rabbi Trust Investments(2)	19				—				19				—				—			19
Energy Contracts - Regulatory Recovery(3)	3				—				1				2				(1		)	2
Total Assets	30				8				20				2				(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)		—				(3		)		—				1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)		—				—				(2		)		—			(2		)
Interest Rate Swaps(4)	(10		)		—				(10		)		—				—			(10		)
Total Liabilities	(15		)		—				(13		)		(2		)		1			(14		)
Net Total Assets (Liabilities)	$	15			$	8			$	7			$	—			$	—		$	15
(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), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.
-4	Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index 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
Regulatory Recovery
We are exposed to energy price risk associated with our gas and purchased power requirements. We reduce our energy price risk through a variety of derivative and non-derivative instruments. 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. See Note 2.
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. Beginning in the third quarter of 2013, the fair value of our power options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented.
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 contracts monthly.
Cash Flow Hedges
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. These 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. This 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 12. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $4 million.
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 September 30,
	2013				2012				2013				2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	1			$	(12	)		$	1			$	(6	)
	UNS Energy								TEP
	Nine Months Ended September 30,
	2013				2012				2013				2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	—			$	(20	)		$	2			$	(7	)
Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At September 30, 2013, UNS Energy and TEP have energy contracts that will settle through the third quarter of 2016.
Derivative Volumes
The volumes associated with our energy contracts were as follows:
	UNS Energy						TEP
	September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
Power Contracts GWh	1,819			2,228			856			820
Gas Contracts GBtu	29,022			17,851			8,504			7,958
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-Sep-13										Range of
	Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Contracts(1)	Market approach		$	1			$	(7	)		Market price per MWh		$	23		-	$	48
(1)	TEP comprises $2 million of the forward contract liabilities.
Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statement.
The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
	Three Months Ended September 30, 2013
	UNS Energy				TEP
	Millions of Dollars
Balances at June 30, 2013	$	(5	)		$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(3		)		(1		)
Settlements	2				—
Balances at September 30, 2013	$	(6	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(2	)		$	—
	Nine Months Ended September 30, 2013
	UNS Energy				TEP
	Millions of Dollars
Balances at December 31, 2012	$	(5	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)		(2		)
Settlements	3				—
Balances at September 30, 2013	$	(6	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(5	)		$	(1	)
	Three Months Ended September 30, 2012
	UNS Energy				TEP
	Millions of Dollars
Balances at June 30, 2012	$	(7	)		$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	—				1
Settlements	1				—
Balances at September 30, 2012	$	(6	)		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	—			$	—
	Nine Months Ended September 30, 2012
	UNS Energy				TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)		—
Settlements	8				—
Balances at September 30, 2012	$	(6	)		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)		$	—
CREDIT RISK
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. The impact of counterparty credit risk and our own credit risk on the fair value of derivative contracts was less than $0.5 million at September 30, 2013 and at December 31, 2012.
Material adverse changes could trigger credit risk-related contingent features. At September 30, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $35 million for UNS Energy and $13 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $35 million for UNS Energy and $13 million for TEP.

CHANGES_IN_ACCUMULATED_OTHER_C

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT	9 Months Ended
	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'
Changes in Accumulated Other Comprehensive Income by Component	'
	CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT
	The realized changes in AOCI by component are as follows:
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		UNS Energy			TEP
		Three Months Ended September 30, 2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(350	)	$	(296	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(612		)	(612		)	Interest Expense Capital Leases
	Commodity Contracts	(556		)	(556		)	Purchased Energy/Purchased Power
	Tax Benefit	601			579
	Realized Losses on Cash Flow Hedges, Net of Taxes	(917		)	(885		)
	Amortization of SERP and Defined Benefit Plans
	Prior Service Costs	(110		)	(110		)	Other Expense
	Tax Benefit	42			42
	Amortization, Net of Taxes	(68		)	(68		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(985	)	$	(953	)
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		UNS Energy			TEP
		Nine Months Ended September 30, 2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(1,026	)	$	(871	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(1,820		)	(1,820		)	Interest Expense Capital Leases
	Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
	Tax Benefit	1,420			1,360
	Realized Losses on Cash Flow Hedges, Net of Taxes	(2,173		)	(2,078		)
	Amortization of SERP and Defined Benefit Plans
	Prior Service Costs	(332		)	(332		)	Other Expense
	Tax Benefit	127			127
	Amortization, Net of Taxes	(205		)	(205		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(2,378	)	$	(2,283	)

POTENTIAL_PURCHASE_OF_GASFIRED

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY	9 Months Ended
	Sep. 30, 2013
Potential Purchase of Gas-Fired Generation Facility [Abstract]	'
Unusual or Infrequent Items Disclosure [Text Block]	'
	POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY
	In August 2013, TEP entered into exclusive negotiations with Entegra Power Group LLC (Entegra) to purchase Unit 3 of the Gila River Generating Station (Gila River Unit 3) located in Gila Bend, Arizona. Gila River Unit 3 is a gas-fired combined cycle unit with a nominal capacity rating of 550 MW.  Although there can be no assurance that TEP and Entegra will reach agreement on TEP's purchase of Gila River Unit 3, TEP anticipates that, if such an agreement is reached, definitive purchase and sale agreements would be executed prior to year-end 2013. TEP further anticipates any such purchase would close by year-end 2014 and would be subject to, among other things, the receipt of required regulatory approvals. UNS Electric may purchase up to 150 MW of Gila River Unit 3, while TEP would purchase the remaining capacity.

RECENTLY_ISSUED_ACCOUNTING_PRO

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	'
	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
	The Financial Accounting Standards Board (FASB) issued guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. On adoption, an entity would 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. This guidance will be effective in the first quarter of 2014. We do not expect the adoption of this guidance to have a material impact on our financial condition, results of operations, or cash flows.
	The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair value and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.
	The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such change to be material. In addition, there will be no changes in the presentations of our other financial statements.

REVIEW_BY_INDEPENDENT_REGISTER

REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	'
	REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
	The UNS Energy and TEP condensed consolidated financial statements as of September 30, 2013, and for the three-month and nine-month periods ended September 30, 2013 and 2012, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their reports (dated November 6, 2013) are included on pages 1 and 2. The reports of PricewaterhouseCoopers LLP state that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their reports on the unaudited financial information because neither of those reports is a “report” or a “part” of the registration statements prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

FINANCIAL_STATEMENT_PRESENTATI1

FINANCIAL STATEMENT PRESENTATION FINANCIAL STATEMENT PRESENTATION (Tables)	9 Months Ended
	Sep. 30, 2013
Disclosure Nature Of Operations And Basis Of Accounting Presentation Additional Information [Abstract]	'
Schedule of Error Corrections and Prior Period Adjustments [Table Text Block]	'
	As a result, in accordance with GAAP, we revised our prior period income statement as follows:
		UNS Energy
		Three Months Ended				Nine Months Ended
		September 30, 2012				September 30, 2012
		As Reported		As Revised		As Reported		As Revised
		Thousands of Dollars				Thousands of Dollars
	Income Statement
	Electric Wholesale Sales	$	32,494	$	29,341	$	98,282	$	88,469
	Purchased Energy	60,238		57,085		174,891		165,078
	Total Fuel and Purchased Energy	175,687		172,534		461,292		451,479
	Total Operating Expenses	330,852		327,699		914,428		904,615

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Regulatory Assets and Liabilities	'
	The following table summarizes changes in regulatory assets and liabilities since December 31, 2012:
		30-Sep-13						31-Dec-12
		UNS			TEP			UNS			TEP
		Energy						Energy
		Millions of Dollars
	Regulatory Assets – Current	$	53		$	36		$	52		$	34
	Regulatory Assets – Noncurrent (1)	201			187			191			178
	Regulatory Liabilities – Current (2)	(57		)	(26		)	(44		)	(21		)
	Regulatory Liabilities – Noncurrent (3)	(298		)	(260		)	(279		)	(241		)
	Total Net Regulatory Assets (Liabilities)	$	(101	)	$	(63	)	$	(80	)	$	(50	)
	(1)	Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment. See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.
	(2)	Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.
	(3)	Regulatory Liabilities – Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

BUSINESS_SEGMENTS_Tables

BUSINESS SEGMENTS (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Reconciliation of Income Statement Items from Segments to Consolidation	'
	We disclose selected financial data for our reportable segments in the following table:
		Reportable Segments
		TEP		UNS			UNS		Non-Reportable Segments			Reconciling			UNS
				Gas			Electric					Adjustments			Energy
															Consolidated
		Millions of Dollars
	Income Statement
	Three Months Ended September 30, 2013
	Operating Revenues – External	$	367	$	16		$	54	$	—		$	—		$	437
	Operating Revenues – Intersegment(1)	4		2			—		4			(10		)	—
	Net Income	64		(1		)	5		—			—			68
	Three Months Ended September 30, 2012
	Operating Revenues – External	$	362	$	16		$	56	$	—		$	—		$	434
	Operating Revenues – Intersegment(1)	5		2			—		5			(12		)	—
	Net Income	45		—			6		—			—			51
		Reportable Segments
		TEP		UNS			UNS		Non-Reportable Segments			Reconciling			UNS
				Gas			Electric					Adjustments			Energy
															Consolidated
		Millions of Dollars
	Income Statement
	Nine Months Ended September 30, 2013
	Operating Revenues – External	$	910	$	90		$	134	$	—		$	—		$	1,134
	Operating Revenues – Intersegment(1)	13		3			1		12			(29		)	—
	Net Income	96		6			11		1			—			114
	Nine Months Ended September 30, 2012
	Operating Revenues – External	$	877	$	89		$	147	$	—		$	—		$	1,113
	Operating Revenues – Intersegment(1)	13		4			1		14			(32		)	—
	Net Income	65		5			14		(1		)	—			83
	(1)	Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]	'
	TEP COMMITMENTS
		Purchase Commitments
		2013		2014		2015		2016		2017		Thereafter		Total
		Millions of Dollars
	Purchased Power, Including Renewable PPA(1)	$	2	$	18	$	6	$	4	$	4	$	58	$	92
	Capital Lease Obligations(2)	—		—		46		—		—		—		46
	RES Performance-Based Incentives(3)	1		1		1		1		1		7		12
	Fuel Transportation(4)	4		5		5		5		5		1		25
	Total Purchase Commitments	$	7	$	24	$	58	$	10	$	10	$	66	$	175
	-1	Purchased Power costs are recoverable from customers through the PPFAC. A portion of the Renewable Power Purchase Agreement (PPA) is recoverable through the PPFAC, with the balance recoverable through the RES tariff.
	-2	In the third and fourth quarters of 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 5.
	-3	The RES Performance-Based Incentive (PBI) costs are recoverable through the RES tariff.
	-4	Fuel Transportation costs are recoverable from customers through the PPFAC.

INCOME_TAXES_Tables

INCOME TAXES (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate	'
	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
		UNS Energy						TEP
		Three Months Ended September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	38		$	29		$	36		$	25
	State Income Tax Expense, Net of Federal Deduction	5			3			5			3
	Federal/State Tax Credits	(1		)	(1		)	(1		)	(1		)
	Other	(1		)	—			(1		)	—
	Total Federal and State Income Tax Expense	41			$	31		$	39		$	27
		UNS Energy						TEP
		Nine Months Ended September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	58		$	47		$	48		$	37
	State Income Tax Expense, Net of Federal Deduction	8			6			6			4
	Federal/State Tax Credits	(2		)	(1		)	(2		)	(1		)
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—			(11		)	—
	Other	(1		)	(1		)	1			(1		)
	Total Federal and State Income Tax Expense	$	52		$	51		$	42		$	39
Summary of Income Tax Contingencies	'
	A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
		UNS Energy			TEP
		Millions of Dollars
	Unrecognized Tax Benefits at December 31, 2012	$	30		$	23
	Additions Based on Tax Positions Taken in the Current Year	1			1
	Reduction of Positions from Prior Year Based on Tax Authority Ruling	(27		)	(22		)
	Unrecognized Tax Benefits at September 30, 2013	$	4		$	2

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2013
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 September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Service Cost	$	4		$	2		$	1		$	1
	Interest Cost	4			4			—			1
	Expected Return on Plan Assets	(5		)	(4		)	—			—
	Actuarial Loss Amortization	2			2			—			—
	Net Periodic Benefit Cost	$	5		$	4		$	1		$	2
		Pension Benefits						Other Retiree Benefits
		Nine Months Ended September 30,
		2013			2012			2013			2012
		Millions of Dollars
	Service Cost	$	10		$	8		$	3		$	2
	Interest Cost	11			12			2			2
	Expected Return on Plan Assets	(15		)	(13		)	(1		)	—
	Actuarial Loss Amortization	7			5			—			—
	Net Periodic Benefit Cost	$	13		$	12		$	4		$	4

UNS_ENERGY_EARNINGS_PER_SHARE_

UNS ENERGY EARNINGS PER SHARE (Tables)	9 Months Ended
	Sep. 30, 2013
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 September 30,						Nine Months Ended September 30,
		2013			2012			2013		2012
		Thousands of Dollars
	Numerator:
	Net Income	$	67,990		$	50,664		$	113,953	$	83,414
	Income from Assumed Conversion of Convertible Senior Notes (1)	—			—			—		1,100
	Adjusted Net Income Available for Diluted Common Stock Outstanding	$	67,990		$	50,664		$	113,953	$	84,514
		Thousands of Shares
	Denominator:
	Weighted Average Shares of Common Stock Outstanding:
	Common Shares Issued	41,472			41,290			41,427		39,835
	Fully Vested Deferred Stock Units	178			156			169		148
	Total Weighted Average Common Stock Outstanding – Basic	41,650			41,446			41,596		39,983
	Effect of Dilutive Securities:
	Convertible Senior Notes (1)	—			—			—		1,417
	Options and Stock Issuable Under Share-Based Compensation Plans	378			417			345		319
	Total Weighted Average Common Stock Outstanding – Diluted	42,028			41,863			41,941		41,719
	(1) In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.
Number of Stock Options to Purchase Shares of Common Stock Excluded from Computation of Diluted Earning Per Share	'
	We excluded the following outstanding stock options, with an exercise price above market, and contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive:
		Three Months Ended September 30,					Nine Months Ended September 30,
		2013		2012			2013		2012
		Thousands of Shares
	Stock Options	—		—			—		67
	Restricted Stock Units	—		—			8		—
	Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	—		—			8		67

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	'
	A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:
		UNS Energy
		Nine Months Ended September 30,
		2013			2012
		Thousands of Dollars
	Net Income	$	113,953		$	83,414
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	111,175			105,319
	Amortization Expense	21,600			26,845
	Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	5,399			4,911
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,280			2,250
	Provision for Retail Customer Bad Debts	1,703			2,017
	Use of RECs for Compliance	12,999			4,017
	Deferred Income Taxes	77,962			63,057
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—
	Pension and Retiree Expense	17,087			16,391
	Pension and Retiree Funding	(27,602		)	(23,649		)
	Share-Based Compensation Expense	2,810			1,952
	Allowance for Equity Funds Used During Construction	(4,145		)	(2,708		)
	Increase (Decrease) to Reflect PPFAC/PGA Recovery	(6,814		)	29,730
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—
	Liquidated Damages for Springerville Unit 3 Outage	—			1,921
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(32,883		)	(28,686		)
	Materials and Fuel Inventory	14,839			(33,038		)
	Accounts Payable	(18,497		)	(5,220		)
	Income Taxes	(15,847		)	(11,738		)
	Interest Accrued	(2,137		)	(1,551		)
	Taxes Other Than Income Taxes	18,718			16,478
	Other	20,473			16,426
	Net Cash Flows – Operating Activities	$	305,034		$	268,138
		TEP
		Nine Months Ended September 30,
		2013			2012
		Thousands of Dollars
	Net Income	$	96,433		$	65,018
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	87,729			82,656
	Amortization Expense	24,393			29,621
	Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	4,602			3,922
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,831			1,628
	Provision for Retail Customer Bad Debts	1,315			1,348
	Use of RECs for Compliance	11,766			3,324
	Deferred Income Taxes	64,132			51,638
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—
	Pension and Retiree Expense	14,909			14,466
	Pension and Retiree Funding	(26,118		)	(20,989		)
	Share-Based Compensation Expense	2,239			1,540
	Allowance for Equity Funds Used During Construction	(2,923		)	(2,265		)
	Increase (Decrease) to Reflect PPFAC Recovery	(5,079		)	25,150
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—
	Liquidated Damages for Springerville Unit 3 Outage	—			1,921
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(42,542		)	(44,269		)
	Materials and Fuel Inventory	14,955			(32,448		)
	Accounts Payable	(8,678		)	4,977
	Income Taxes	(10,681		)	(11,424		)
	Interest Accrued	1,008			2,729
	Taxes Other Than Income Taxes	17,405			16,710
Other	15,234			11,898
Net Cash Flows – Operating Activities	$	254,179		$	207,151

FAIR_VALUE_MEASUREMENTS_DERIVA1

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments	'
	The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
				30-Sep-13								31-Dec-12
		Fair Value		Carrying				Fair				Carrying				Fair
		Hierarchy		Value				Value				Value				Value
				Millions of Dollars
	Assets:
	TEP Investment in Lease Debt	Level 2		$	—			$	—			$	9			$	9
	TEP Investment in Lease Equity	Level 3		36				24				36				23
	Liabilities:
	Long-Term Debt
	UNS Energy	Level 2		1,506				1,522				1,498				1,583
	TEP	Level 2		1,224				1,215				1,223				1,271
Schedule of Fair Value Measurements of Financial Assets and Liabilities	'
		UNS Energy
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Sep-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	31			$	31			$	—			$	—			$	—		$	31
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	21				—				21				—				—			21
	Energy Contracts - Regulatory Recovery(3)	2				—				1				1				(2		)	—
	Total Assets	56				33				22				1				(2		)	54
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(11		)		—				(5		)		(6		)		2			(9		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(8		)		—				(8		)		—				—			(8		)
	Total Liabilities	(20		)		—				(13		)		(7		)		2			(18		)
	Net Total Assets (Liabilities)	$	36			$	33			$	9			$	(6	)		$	—		$	36
		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-12
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	20			$	20			$	—			$	—			$	—		$	20
	Restricted Cash(1)	7				7				—				—				—			7
	Rabbi Trust Investments(2)	19				—				19				—				—			19
	Energy Contracts - Regulatory Recovery(3)	7				—				2				5				(5		)	2
	Total Assets	53				27				21				5				(5		)	48
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(15		)		—				(7		)		(8		)		5			(10		)
	Energy Contracts - Cash Flow Hedge(3)	(2		)		—				—				(2		)		—			(2		)
	Interest Rate Swaps(4)	(10		)		—				(10		)		—				—			(10		)
	Total Liabilities	(27		)		—				(17		)		(10		)		5			(22		)
	Net Total Assets (Liabilities)	$	26			$	27			$	4			$	(5	)		$	—		$	26
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		30-Sep-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	15			$	15			$	—			$	—			$	—		$	15
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	21				—				21				—				—			21
	Energy Contracts - Regulatory Recovery(3)	1				—				1				—				(1		)	—
	Total Assets	39				17				22				—				(1		)	38
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(3		)		—				(2		)		(1		)		1			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(8		)		—				(8		)		—				—			(8		)
	Total Liabilities	(12		)		—				(10		)		(2		)		1			(11		)
	Net Total Assets (Liabilities)	$	27			$	17			$	12			$	(2	)		$	—		$	27
		TEP
		Total				Level 1				Level 2				Level 3				Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
		31-Dec-12
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	1			$	1			$	—			$	—			$	—		$	1
	Restricted Cash(1)	7				7				—				—				—			7
	Rabbi Trust Investments(2)	19				—				19				—				—			19
	Energy Contracts - Regulatory Recovery(3)	3				—				1				2				(1		)	2
	Total Assets	30				8				20				2				(1		)	29
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(3		)		—				(3		)		—				1			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(2		)		—				—				(2		)		—			(2		)
	Interest Rate Swaps(4)	(10		)		—				(10		)		—				—			(10		)
	Total Liabilities	(15		)		—				(13		)		(2		)		1			(14		)
Net Total Assets (Liabilities)	$	15			$	8			$	7			$	—			$	—		$	15
(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), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.
-4	Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index 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 INS
Financial Impact of Energy Contracts [Table Text Block]	'
	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 September 30,
		2013				2012				2013				2012
		Millions of Dollars
	Increase (Decrease) to Regulatory Assets/Liabilities	$	1			$	(12	)		$	1			$	(6	)
		UNS Energy								TEP
		Nine Months Ended September 30,
		2013				2012				2013				2012
		Millions of Dollars
	Increase (Decrease) to Regulatory Assets/Liabilities	$	—			$	(20	)		$	2			$	(7	)
Derivative Volumes [Table Text Block]	'
	The volumes associated with our energy contracts were as follows:
		UNS Energy						TEP
		September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
	Power Contracts GWh	1,819			2,228			856			820
	Gas Contracts GBtu	29,022			17,851			8,504			7,958
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-Sep-13										Range of
		Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Contracts(1)	Market approach		$	1			$	(7	)		Market price per MWh		$	23		-	$	48
	(1)	TEP comprises $2 million of the forward contract liabilities.
Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities	'
	.
	The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
		Three Months Ended September 30, 2013
		UNS Energy				TEP
		Millions of Dollars
	Balances at June 30, 2013	$	(5	)		$	(1	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(3		)		(1		)
	Settlements	2				—
	Balances at September 30, 2013	$	(6	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(2	)		$	—
		Nine Months Ended September 30, 2013
		UNS Energy				TEP
		Millions of Dollars
	Balances at December 31, 2012	$	(5	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)		(2		)
	Settlements	3				—
	Balances at September 30, 2013	$	(6	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(5	)		$	(1	)
		Three Months Ended September 30, 2012
		UNS Energy				TEP
		Millions of Dollars
	Balances at June 30, 2012	$	(7	)		$	(1	)
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	—				1
	Settlements	1				—
	Balances at September 30, 2012	$	(6	)		$	—
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	—			$	—
		Nine Months Ended September 30, 2012
		UNS Energy				TEP
		Millions of Dollars
	Balances at December 31, 2011	$	(10	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)		—
	Settlements	8				—
	Balances at September 30, 2012	$	(6	)		$	—
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)		$	—

CHANGES_IN_ACCUMULATED_OTHER_C1

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT CHANGES IN ACCUMULATIVE OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)	9 Months Ended
	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	The realized changes in AOCI by component are as follows:
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		UNS Energy			TEP
		Three Months Ended September 30, 2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(350	)	$	(296	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(612		)	(612		)	Interest Expense Capital Leases
	Commodity Contracts	(556		)	(556		)	Purchased Energy/Purchased Power
	Tax Benefit	601			579
	Realized Losses on Cash Flow Hedges, Net of Taxes	(917		)	(885		)
	Amortization of SERP and Defined Benefit Plans
	Prior Service Costs	(110		)	(110		)	Other Expense
	Tax Benefit	42			42
	Amortization, Net of Taxes	(68		)	(68		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(985	)	$	(953	)
	Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
		UNS Energy			TEP
		Nine Months Ended September 30, 2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(1,026	)	$	(871	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(1,820		)	(1,820		)	Interest Expense Capital Leases
	Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
	Tax Benefit	1,420			1,360
	Realized Losses on Cash Flow Hedges, Net of Taxes	(2,173		)	(2,078		)
	Amortization of SERP and Defined Benefit Plans
	Prior Service Costs	(332		)	(332		)	Other Expense
	Tax Benefit	127			127
	Amortization, Net of Taxes	(205		)	(205		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(2,378	)	$	(2,283	)

FINANCIAL_STATEMENT_PRESENTATI2

FINANCIAL STATEMENT PRESENTATION - Additional Information (Detail) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Quantifying Misstatement in Current Year Financial Statements [Line Items]	'	'	'	'
Quantifying Misstatement in Current Year Financial Statements, Amount	'	$3,000,000	'	$10,000,000
Electric Wholesale Sales	27,529,000	29,341,000	92,581,000	88,469,000
Utilities Operating Expense, Purchased Power	67,429,000	57,085,000	189,384,000	165,078,000
Total Fuel and Purchased Energy	157,071,000	172,534,000	451,587,000	451,479,000
Total Operating Expenses	307,276,000	327,699,000	903,936,000	904,615,000
Scenario, Previously Reported [Member]	'	'	'	'
Quantifying Misstatement in Current Year Financial Statements [Line Items]	'	'	'	'
Electric Wholesale Sales	'	32,494,000	'	98,282,000
Utilities Operating Expense, Purchased Power	'	60,238,000	'	174,891,000
Total Fuel and Purchased Energy	'	175,687,000	'	461,292,000
Total Operating Expenses	'	$330,852,000	'	$914,428,000

REGULATORY_MATTERS_Additional_

REGULATORY MATTERS - Additional Information (Detail) (USD $)	9 Months Ended		1 Months Ended	9 Months Ended		1 Months Ended		1 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Jun. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2013	Jun. 30, 2013	Jun. 30, 2013	Oct. 31, 2013	Oct. 31, 2013
			TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	UNS ELECTRIC, INC. [Member]	Uns Gas Incorporated [Member]	Before July 1, 2013 [Member]	After June 30, 2013 [Member]	Regulatory Clause Revenues Over-Recovered [Member]	Regulatory Clause Revenues Over-Recovered [Member]
								TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	Before November 1, 2013 [Member]	From November 1, 2013 through April 30, 2014 [Member]
										Uns Gas Incorporated [Member]	Uns Gas Incorporated [Member]
2013 TEP Rate Order	'	'	'	'	'	'	'	'	'	'	'
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	'	'	'4 years	'	'	'	'	'	'	'	'
Base Rate Increase Approved	'	'	$76,000,000	'	'	'	'	'	'	'	'
Fair value of rate base	'	'	2,300,000,000	'	'	283,000,000	'	'	'	'	'
Requested Rate of Return on Equity	'	'	'	'	'	9.50%	'	'	'	'	'
Requested Long Term Cost of Debt	'	'	'	'	'	5.97%	'	'	'	'	'
Requested Weighted Average Cost of Capital	'	'	'	'	'	7.83%	'	'	'	'	'
Requested Equity Portion of Capital Structure	'	'	'	'	'	52.60%	'	'	'	'	'
Requested Long Term Debt Portion of Capital Structure	'	'	'	'	'	47.40%	'	'	'	'	'
Purchased Gas Adjustor Rate	'	'	'	'	'	'	'	'	'	0.045	0.1
Approved Rate of Return on Equity	'	'	10.00%	'	'	'	'	'	'	'	'
Approved Long Term Cost of Debt	'	'	5.18%	'	'	'	'	'	'	'	'
Approved Short-Term Cost of Debt	'	'	1.42%	'	'	'	'	'	'	'	'
Approved Weighted Average Cost of Capital	'	'	7.26%	'	'	'	'	'	'	'	'
Approved Equity Portion of Capital Structure	'	'	43.50%	'	'	'	'	'	'	'	'
Approved Long Term Debt Portion of Capital Structure	'	'	56.00%	'	'	'	'	'	'	'	'
Approved Short-Term Debt Portion of Capital Structure	'	'	0.50%	'	'	'	'	'	'	'	'
Approved Rate of Return on the Fair Value Increment of Rate Base	'	'	0.68%	'	'	'	'	'	'	'	'
Original Cost Rate Base	'	'	1,500,000,000	'	'	213,000,000	'	'	'	'	'
Requested Return on Fair Value Increment of Rate Base	'	'	'	'	'	0.50%	'	'	'	'	'
Fair Value Increment Of Rate Base	'	'	800,000,000	'	'	70,000,000	'	'	'	'	'
Change in Composite Rate	'	'	'	'	'	'	'	3.32%	3.00%	'	'
Expected Change in Annual Depreciation	'	'	11,000,000	'	'	'	'	'	'	'	'
Purchased Power And Fuel Adjustment Clause Rate	'	'	0.001388	'	'	'	'	'	'	'	'
PPFAC Reduction - TEP Rate Order	3,000,000	0	3,000,000	3,000,000	0	'	'	'	'	'	'
Deferred Costs Related to San Juan Mine Fire	'	'	10,000,000	'	'	'	'	'	'	'	'
Cap on Increase in Lost Fixed Cost Recovery Rate	'	'	1.00%	'	'	'	'	'	'	'	'
Environmental Compliance Adjustor Capped Rate	'	'	0.00025	'	'	'	'	'	'	'	'
Retail Revenue Cap on Environmental Compliance Adjustor	'	'	0.25%	'	'	'	'	'	'	'	'
Proposed Base Rate Increase	'	'	'	'	'	3,000,000	'	'	'	'	'
Customer Refund Liability, Current	'	'	'	'	'	'	$17,000,000	'	'	'	'

REGULATORY_MATTERS_Regulatory_

REGULATORY MATTERS - Regulatory Assets and Liabilities (Detail) (USD $)	Sep. 30, 2013		Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]	'		'
Regulatory Assets—Current	$52,709,000		$51,619,000
Regulatory Assets—Noncurrent	200,705,000	[1]	191,077,000	[1]
Regulatory Liabilities - Current	-56,987,000	[2]	-43,516,000	[2]
Regulatory Liabilities - Noncurrent	-297,699,000	[3]	-279,111,000	[3]
Total Net Regulatory Assets (Liabilities)	-101,000,000		-80,000,000
TUCSON ELECTRIC POWER COMPANY	'		'
Regulatory Assets And Liabilities [Line Items]	'		'
Regulatory Assets—Current	36,283,000		34,345,000	[1]
Regulatory Assets—Noncurrent	186,626,000	[1]	178,330,000	[1]
Regulatory Liabilities - Current	-26,440,000	[2]	-20,822,000	[2]
Regulatory Liabilities - Noncurrent	-259,523,000	[3]	-241,189,000	[3]
Total Net Regulatory Assets (Liabilities)	($63,000,000)		($50,000,000)
[1]	Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment. See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.
[2]	Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.
[3]	Regulatory Liabilities – Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

REGULATORY_MATTERS_Future_Impl

REGULATORY MATTERS Future Implications of Discontinuing Application of Regulatory Accounting (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
TUCSON ELECTRIC POWER COMPANY	'
Regulatory Liabilities [Line Items]	'
Potential Extraordinary Gains (Losses) from Discontinuing Application of Regulatory Accounting	$113
Potential After-Tax Loss in Accumulated Other Comprehensive Income From Discontinuing Application of Regulatory Accounting	75
Uns Gas Incorporated [Member]	'
Regulatory Liabilities [Line Items]	'
Potential Extraordinary Gains (Losses) from Discontinuing Application of Regulatory Accounting	26
Potential After-Tax Loss in Accumulated Other Comprehensive Income From Discontinuing Application of Regulatory Accounting	2
UNS ELECTRIC, INC. [Member]	'
Regulatory Liabilities [Line Items]	'
Potential Extraordinary Gains (Losses) from Discontinuing Application of Regulatory Accounting	3
Potential After-Tax Loss in Accumulated Other Comprehensive Income From Discontinuing Application of Regulatory Accounting	$3

BUSINESS_SEGMENTS_BUSINESS_SEG

BUSINESS SEGMENTS BUSINESS SEGMENTS - Reporting (Details)	9 Months Ended
	Sep. 30, 2013
	unit
Segment Reporting - Number of Reportable Segments [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				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	$437,041,000		$434,108,000		$1,134,399,000		$1,113,492,000
Related Party Transaction, Other Revenues from Transactions with Related Party	0	[1]	0	[1]	0	[1]	0	[1]
Net Income	67,990,000		50,664,000		113,953,000		83,414,000
TUCSON ELECTRIC POWER COMPANY	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	371,239,000		366,910,000		923,253,000		890,307,000
Related Party Transaction, Other Revenues from Transactions with Related Party	4,000,000		5,000,000	[1]	13,000,000	[1]	13,000,000	[1]
Net Income	64,167,000		44,569,000		96,433,000		65,018,000
Uns Gas Incorporated [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Related Party Transaction, Other Revenues from Transactions with Related Party	2,000,000	[1]	2,000,000	[1]	3,000,000	[1]	4,000,000	[1]
Net Income	-1,000,000		0		6,000,000		5,000,000
UNS ELECTRIC, INC. [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Related Party Transaction, Other Revenues from Transactions with Related Party	0	[1]	0	[1]	1,000,000	[1]	1,000,000	[1]
Net Income	5,000,000		6,000,000		11,000,000		14,000,000
Other [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Related Party Transaction, Other Revenues from Transactions with Related Party	4,000,000	[1]	5,000,000	[1]	12,000,000	[1]	14,000,000	[1]
Net Income	0		0		1,000,000		-1,000,000
Reconciling Adjustments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Related Party Transaction, Other Revenues from Transactions with Related Party	-10,000,000	[1]	-12,000,000	[1]	-29,000,000	[1]	-32,000,000	[1]
Net Income	0		0		0		0
Revenue from External Parties [Member] | TUCSON ELECTRIC POWER COMPANY	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	367,000,000		362,000,000		910,000,000		877,000,000
Revenue from External Parties [Member] | Uns Gas Incorporated [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	16,000,000		16,000,000		90,000,000		89,000,000
Revenue from External Parties [Member] | UNS ELECTRIC, INC. [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	54,000,000		56,000,000		134,000,000		147,000,000
Revenue from External Parties [Member] | Other [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	0		0		0		0
Revenue from External Parties [Member] | Reconciling Adjustments [Member]	'		'		'		'
Segment Reporting, Revenue Reconciling Item [Line Items]	'		'		'		'
Revenues	$0		$0		$0		$0
[1]	Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS - TEP and UNS Commitments (Detail) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
TUCSON ELECTRIC POWER COMPANY	'		'
Commitments And Contingencies [Line Items]	'		'
Capital Leases, Future Minimum Payments Due, Next Twelve Months	$0	[1]	'
Capital Leases, Future Minimum Payments Due in Two Years	0	[1]	'
Capital Leases, Future Minimum Payments Due in Three Years	46	[1]	'
Capital Leases, Future Minimum Payments Due in Four Years	0	[1]	'
Capital Leases, Future Minimum Payments Due in Five Years	0	[1]	'
Capital Leases, Future Minimum Payments Due Thereafter	0	[1]	'
Capital Leases, Future Minimum Payments Due	46	[1]	'
Company Share Of Reclamation Costs At Expiration Dates Of Coal Supply Agreements	27		'
Mine Reclamation and Closing Liability, Noncurrent	18		16
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	7		'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	24		'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	58		'
Unrecorded Unconditional Purchase Obligation, Due within Four Years	10		'
Unrecorded Unconditional Purchase Obligation, Due within Five Years	10		'
Unrecorded Unconditional Purchase Obligation, Due after Five Years	66		'
Unrecorded Unconditional Purchase Obligation	175		'
TUCSON ELECTRIC POWER COMPANY | Purchased Power [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	2	[2]	'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	18	[2]	'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	6	[2]	'
Unrecorded Unconditional Purchase Obligation, Due within Four Years	4	[2]	'
Unrecorded Unconditional Purchase Obligation, Due within Five Years	4	[2]	'
Unrecorded Unconditional Purchase Obligation, Due after Five Years	58	[2]	'
Unrecorded Unconditional Purchase Obligation	92	[2]	'
TUCSON ELECTRIC POWER COMPANY | RES Performance Based Incentives Minimum Commitment [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	1	[3]	'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	1	[3]	'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	1	[3]	'
Unrecorded Unconditional Purchase Obligation, Due within Four Years	1	[3]	'
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1	[3]	'
Unrecorded Unconditional Purchase Obligation, Due after Five Years	7	[3]	'
Unrecorded Unconditional Purchase Obligation	12	[3]	'
TUCSON ELECTRIC POWER COMPANY | 486210 Pipeline Transportation of Natural Gas [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	4	[4]	'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	5	[4]	'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5	[4]	'
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5	[4]	'
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5	[4]	'
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1	[4]	'
Unrecorded Unconditional Purchase Obligation	25	[4]	'
Uns Gas Incorporated [Member] | Fuel [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	2		'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	3		'
Unrecorded Unconditional Purchase Obligation, Due within Four Years	2		'
Uns Gas Incorporated [Member] | 486210 Pipeline Transportation of Natural Gas [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	3		'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	9		'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	9		'
Unrecorded Unconditional Purchase Obligation, Due within Four Years	9		'
Unrecorded Unconditional Purchase Obligation, Due within Five Years	10		'
Unrecorded Unconditional Purchase Obligation, Due after Five Years	56		'
UNS ELECTRIC, INC. [Member] | Purchased Power [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	1		'
Unrecorded Unconditional Purchase Obligation, Due within Three Years	$4		'
Tucson to Nogales [Member]	'		'
Commitments And Contingencies [Line Items]	'		'
Transmission line from Tucson to Nogales	60		'
[1]	In the third and fourth quarters of 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 5.
[2]	Purchased Power costs are recoverable from customers through the PPFAC. A portion of the Renewable Power Purchase Agreement (PPA) is recoverable through the PPFAC, with the balance recoverable through the RES tariff.
[3]	The RES Performance-Based Incentive (PBI) costs are recoverable through the RES tariff.
[4]	Fuel Transportation costs are recoverable from customers through the PPFAC

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS - TEP Contingencies (Detail) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Tucson to Nogales [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Transmission line from Tucson to Nogales	'	60	'
Transmission Line, in KV	'	345	'
TUCSON ELECTRIC POWER COMPANY	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Mine Reclamation and Closing Liability, Noncurrent	'	$18	$16
Company Share Of Reclamation Costs At Expiration Dates Of Coal Supply Agreements	'	27	'
Payment as a Result of Power Outage	2	'	'
TUCSON ELECTRIC POWER COMPANY | San Juan [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Percentage of ownership in generating station	'	20.00%	'
Percentage of Ownership in Generating Units 1 & 2	'	50.00%	'
TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Percentage of ownership in generating station	'	7.00%	'
Estimated Loss Accrual Related to Four Corners Generating Station	'	1	'
TUCSON ELECTRIC POWER COMPANY | Tucson to Nogales [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Regulatory Assets	'	5	'
UNS ELECTRIC, INC. [Member] | Tucson to Nogales [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Regulatory Assets	'	0.2	'
Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member] | TUCSON ELECTRIC POWER COMPANY | San Juan [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Estimate of Possible Loss Contingency	'	5	'
Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member] | TUCSON ELECTRIC POWER COMPANY | San Juan [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Estimate of Possible Loss Contingency	'	1	'
Assessment for Coal Severance Tax, Coal Supplier [Member] | TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Estimate of Possible Loss Contingency	'	30	'
Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member] | TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]	'	'	'
Commitments And Contingencies [Line Items]	'	'	'
Estimate of Possible Loss Contingency	'	$1	'

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS - Environmental Matters (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	1 Months Ended
In Millions, unless otherwise specified	Jul. 31, 2013	Sep. 30, 2013
Navajo [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Estimated Capital Expenditure Related to Installation of Baghouses	'	$43
Estimated Future Annual Operating Costs For Mercury Emmission Control Equipment and Baghouses	'	1
Estimated Capital Cost if SCR is Required	'	42
Estimated Capital Expenditures Related to Installation of Mercury Control Equipment	'	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	'
Four Corner [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	'	1
Estimated Capital Cost if SCR is Required	'	35
Estimated Capital Expenditures Related to Installation of Mercury Control Equipment	'	1
Number of Units on Which SCR Technology has to be Installed	'	5
Estimated Annual Future Operating Costs for SCR Equipment	'	2
Springerville [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	'	3
Estimated Capital Expenditures Related to Installation of Mercury Control Equipment	'	5
San Juan [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Number of Years Allowed For Installation of SCRS	'	'5 years
Book Value of Generating Units	'	114
Estimated Annual Future Operating Costs for SCR Equipment	'	6
Estimated Capital Expenditures Related To Installation Of Selective Non Catalytic Reductions	'	35
Estimated Annual Future Operating Costs for SNCR Equipment	'	1
Generating Capacity in Jointly Owned Facility, in MWs	'	340
Percentage of Ownership in Generating Units 1 & 2	'	50.00%
San Juan [Member] | Minimum [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Estimated Capital Cost if SCR is Required	'	180
San Juan [Member] | Maximum [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Estimated Capital Cost if SCR is Required	'	$200

DEBT_CREDIT_FACILITIES_AND_CAP1

DEBT, CREDIT FACILITIES AND CAPITAL LEASE OBLIGATIONS (Detail) (USD $)

1 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

1 Months Ended

1 Months Ended

Oct. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Aug. 31, 2013

Mar. 31, 2013

Sep. 30, 2012

Mar. 31, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Letter of Credit [Member]

Margin After Credit Rating Upgrade [Member]

Margin After Credit Rating Upgrade [Member]

Margin After Credit Rating Upgrade [Member]

Margin After Credit Rating Upgrade [Member]

Margin before Credit Rating Upgrade [Member]

Margin before Credit Rating Upgrade [Member]

Margin before Credit Rating Upgrade [Member]

Margin before Credit Rating Upgrade [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Springerville Unit One Lease [Member]

Springerville Unit One Lease [Member]

Springerville Unit One Lease [Member]

Springerville Unit One Lease [Member]

Unsecured Tax Exempt Bonds [Member]

Unsecured Tax Exempt Bonds [Member]

Unsecured Tax Exempt Bonds Redemption [Member]

TUCSON ELECTRIC POWER COMPANY

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Letter of Credit [Member]

2010 TEP Reimbursement Agreement [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Letter of Credit [Member]

2010 TEP Reimbursement Agreement [Member]

Letter of Credit [Member]

Margin After Credit Rating Upgrade [Member]

Margin After Credit Rating Upgrade [Member]

Margin After Credit Rating Upgrade [Member]

Margin After Mortgage Bonds Cancellation [Member]

Margin After Mortgage Bonds Cancellation [Member]

Margin After Mortgage Bonds Cancellation [Member]

MW

MW

MW

MW

TUCSON ELECTRIC POWER COMPANY

UNS Energy Corporation [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Energy Corporation [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Revolving Credit Facility [Member]

Letter of Credit [Member]

2010 TEP Reimbursement Agreement [Member]

Revolving Credit Facility [Member]

Letter of Credit [Member]

2010 TEP Reimbursement Agreement [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

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease Arrangement, Purchase Price per kW

'

478

478

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generating Capacity in Jointly Owned Facility, in MWs

'

387

387

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Capital Lease Obligation

$55,000,000

$39,000,000

$39,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of Interest Committed to Purchase

0.106

'

'

0.248

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generating Capacity Purchased, in MWs

41

192

192

96

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease Arrangement, Fair Market Value Purchase Price

20,000,000

'

'

46,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

91,000,000

193,000,000

91,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed interest rate of long-term debt

'

'

'

'

4.00%

'

6.38%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Increase, Accrued Interest

'

'

'

'

'

'

500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capitalized value related to issuance of Bonds

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

1.00%

1.50%

1.00%

1.25%

1.13%

1.75%

1.13%

1.50%

'

1.00%

1.00%

1.25%

1.25%

1.25%

1.75%

Line of Credit Facility, Amount Outstanding

'

'

'

'

'

'

'

186,000,000

'

'

'

'

'

'

'

'

186,000,000

'

'

'

'

'

'

Percentage of Interest Owned after Close of Purchases

0.495

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Utility Plant under Capital Lease

55,000,000

39,000,000

39,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Collateral Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$423,000,000

'

'

'

'

'

'

INCOME_TAXES_Differences_betwe

INCOME TAXES - Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate (Detail) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Taxes [Line Items]	'	'	'	'	'
Statutory tax rate	'	'	'	35.00%	'
Federal Income Tax Expense at Statutory Rate	'	$38,000,000	$29,000,000	$58,000,000	$47,000,000
State Income Tax Expense, Net of Federal Deduction	'	5,000,000	3,000,000	8,000,000	6,000,000
Federal/State Tax Credits	'	-1,000,000	-1,000,000	-2,000,000	-1,000,000
Investment Tax Credit Basis Difference	-11,000,000	'	'	-11,039,000	0
Other	'	-1,000,000	0	-1,000,000	-1,000,000
Income Tax Expense (Benefit)	'	40,914,000	31,111,000	51,947,000	51,430,000
TUCSON ELECTRIC POWER COMPANY	'	'	'	'	'
Income Taxes [Line Items]	'	'	'	'	'
Federal Income Tax Expense at Statutory Rate	'	36,000,000	25,000,000	48,000,000	37,000,000
State Income Tax Expense, Net of Federal Deduction	'	5,000,000	3,000,000	6,000,000	4,000,000
Federal/State Tax Credits	'	-1,000,000	-1,000,000	-2,000,000	-1,000,000
Investment Tax Credit Basis Difference	-11,000,000	'	'	-10,751,000	0
Other	'	-1,000,000	0	1,000,000	-1,000,000
Income Tax Expense (Benefit)	'	$38,828,000	$27,150,000	$41,737,000	$39,423,000

INCOME_TAXES_Uncertain_Tax_Pos

INCOME TAXES - Uncertain Tax Positions (Details) (USD $)	1 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Feb. 28, 2013	Sep. 30, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'
Unrecognized Tax Benefits at December 31, 2012	'	$30
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	'	1
Reductions Based on Settlements with Tax Authorities	-28	-27
Unrecognized Tax Benefits at September 30, 2013	'	4
TUCSON ELECTRIC POWER COMPANY	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'
Unrecognized Tax Benefits at December 31, 2012	'	23
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	'	1
Reductions Based on Settlements with Tax Authorities	-22	-22
Unrecognized Tax Benefits at September 30, 2013	'	$2

EMPLOYEE_BENEFIT_PLANS_Compone

EMPLOYEE BENEFIT PLANS - Components of Net Periodic Benefit Cost (Detail) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits [Member]	'	'	'	'
Components of Net Periodic Benefit Plan Cost	'	'	'	'
Service Cost	$4	$2	$10	$8
Interest Cost	4	4	11	12
Expected Return on Plan Assets	-5	-4	-15	-13
Amortization of Net Loss	2	2	7	5
Net Periodic Benefit Plan Cost	5	4	13	12
Other Postretirement Benefits [Member]	'	'	'	'
Components of Net Periodic Benefit Plan Cost	'	'	'	'
Service Cost	1	1	3	2
Interest Cost	0	1	2	2
Expected Return on Plan Assets	0	0	-1	0
Amortization of Net Loss	0	0	0	0
Net Periodic Benefit Plan Cost	$1	$2	$4	$4

SHAREBASED_COMPENSATION_PLANS_

SHARE-BASED COMPENSATION PLANS - Additional Information (Detail) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

31-May-13

Feb. 28, 2013

Feb. 28, 2013

Feb. 28, 2013

Feb. 28, 2013

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Performance Shares [Member]

Based On Monte Carlo Simulation [Member]

Based On Cumulative Net Income [Member]

Director [Member]

Officer [Member]

Officer [Member]

Performance Shares [Member]

Performance Shares [Member]

Officer [Member]

Officer [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Granted, Shares

'

'

'

'

'

'

'

'

8,870

21,560

43,120

'

'

Granted

'

'

'

'

'

'

'

'

$48.99

$46.23

'

$45.54

$46.23

Share based compensation expense, net of amounts capitalized

$1

$1

$3

$2

$1

$1

$2

$2

'

'

'

'

'

Total unrecognized compensation expense on non-vested share-based compensation

$4

'

$4

'

'

'

'

'

'

'

'

'

'

Total number of shares awarded but not yet issued, including target performance based shares under the share-based compensation plans

1,000,000

'

1,000,000

'

'

'

'

'

'

'

'

'

'

UNS_ENERGY_EARNINGS_PER_SHARE_1

UNS ENERGY EARNINGS PER SHARE - Effects of Dilutive Common Stock on Weighted-Average Number of Shares (Detail) (USD $)	3 Months Ended				9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Numerator:	'		'		'		'
Net Income	$67,990		$50,664		$113,953		$83,414
Dilutive Securities, Effect on Basic Earnings Per Share	0	[1]	0	[1]	0	[1]	1,100	[1]
Undistributed Earnings, Diluted	$67,990		$50,664		$113,953		$84,514
Weighted Average Shares of Common Stock Outstanding:	'		'		'		'
Common Shares Issued	41,472		41,290		41,427		39,835
Fully Vested Deferred Stock Units	178		156		169		148
Total Weighted Average Shares of Common Stock Outstanding and Participating Securities - Basic	41,650		41,446		41,596		39,983
Effect of Dilutive Securities:	'		'		'		'
Incremental Common Shares Attributable to Conversion of Debt Securities	0	[1]	0	[1]	0	[1]	1,417	[1]
Options and Stock Issuable Under Share-Based Compensation Plans	378		417		345		319
Total Shares - Diluted	42,028		41,863		41,941		41,719
[1]	In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

UNS_ENERGY_EARNINGS_PER_SHARE_2

UNS ENERGY EARNINGS PER SHARE - Number of Stock Options to Purchase Shares of Common Stock Excluded from Computation of Diluted Earning Per Share (Detail)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stock Options Excluded from the Diluted EPS Computation	0	0	8	67
Stock Options [Member]	'	'	'	'
Stock Options Excluded from the Diluted EPS Computation	0	0	0	67
Restricted Stock Units (RSUs) [Member]	'	'	'	'
Stock Options Excluded from the Diluted EPS Computation	0	0	8	0

SUPPLEMENTAL_CASH_FLOW_INFORMA2

SUPPLEMENTAL CASH FLOW INFORMATION - Reconciliation of Net Income to Net Cash Flows from Operating Activities (Detail) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Supplemental Cash Flow Information [Line Items]	'	'	'	'	'
Net Income	'	$67,990	$50,664	$113,953	$83,414
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities	'	'	'	'	'
Depreciation Expense	'	38,204	35,145	111,175	105,319
Amortization of Deferred Charges	'	5,193	9,069	21,600	26,845
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	'	'	'	5,399	4,911
Amortization of Deferred Debt-Related Costs Included in Interest Expense	'	'	'	2,280	2,250
Provision for Retail Customer Bad Debts	'	'	'	1,703	2,017
Use of RECs for Compliance	'	'	'	12,999	4,017
Deferred Income Taxes	'	'	'	77,962	63,057
Investment Tax Credit Basis Adjustment	-11,000	'	'	-11,039	0
Pension and Postretirement Expense	'	'	'	17,087	16,391
Pension and Postretirement Funding	'	'	'	-27,602	-23,649
Share-Based Compensation Expense	'	'	'	2,810	1,952
Allowance for Equity Funds Used During Construction	'	'	'	-4,145	-2,708
Increase (Decrease) to Reflect PPFAC Recovery	'	-3,521	18,076	-6,814	29,730
PPFAC Reduction - TEP Rate Order	'	'	'	3,000	0
Liquidated Damages	'	'	'	0	1,921
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately	'	'	'	'	'
Accounts Receivable	'	'	'	-32,883	-28,686
Materials and Fuel Inventory	'	'	'	14,839	-33,038
Accounts Payable	'	'	'	-18,497	-5,220
Income Taxes	'	'	'	-15,847	-11,738
Interest Accrued	'	'	'	-2,137	-1,551
Taxes Other Than Income Taxes	'	'	'	18,718	16,478
Other	'	'	'	20,473	16,426
Net Cash Provided by (Used in) Operating Activities	'	'	'	305,034	268,138
TUCSON ELECTRIC POWER COMPANY	'	'	'	'	'
Supplemental Cash Flow Information [Line Items]	'	'	'	'	'
Net Income	'	64,167	44,569	96,433	65,018
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities	'	'	'	'	'
Depreciation Expense	'	30,311	27,644	87,729	82,656
Amortization of Deferred Charges	'	6,118	10,001	24,393	29,621
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	'	'	'	4,602	3,922
Amortization of Deferred Debt-Related Costs Included in Interest Expense	'	'	'	1,831	1,628
Provision for Retail Customer Bad Debts	'	'	'	1,315	1,348
Use of RECs for Compliance	'	'	'	11,766	3,324
Deferred Income Taxes	'	'	'	64,132	51,638
Investment Tax Credit Basis Adjustment	-11,000	'	'	-10,751	0
Pension and Postretirement Expense	'	'	'	14,909	14,466
Pension and Postretirement Funding	'	'	'	-26,118	-20,989
Share-Based Compensation Expense	'	'	'	2,239	1,540
Allowance for Equity Funds Used During Construction	'	'	'	-2,923	-2,265
Increase (Decrease) to Reflect PPFAC Recovery	'	-7,992	20,025	-5,079	25,150
PPFAC Reduction - TEP Rate Order	3,000	'	'	3,000	0
Liquidated Damages	'	'	'	0	1,921
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately	'	'	'	'	'
Accounts Receivable	'	'	'	-42,542	-44,269
Materials and Fuel Inventory	'	'	'	14,955	-32,448
Accounts Payable	'	'	'	-8,678	4,977
Income Taxes	'	'	'	-10,681	-11,424
Interest Accrued	'	'	'	1,008	2,729
Taxes Other Than Income Taxes	'	'	'	17,405	16,710
Other	'	'	'	15,234	11,898
Net Cash Provided by (Used in) Operating Activities	'	'	'	$254,179	$207,151

SUPPLEMENTAL_CASH_FLOW_INFORMA3

SUPPLEMENTAL CASH FLOW INFORMATION SUPPLEMENTAL CASH FLOW INFORMATION - Non-Cash Transactions (Details) (USD $)	1 Months Ended		3 Months Ended	9 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2012	Oct. 31, 2013	Sep. 30, 2013	Sep. 30, 2013	Mar. 31, 2013	Sep. 30, 2012	Sep. 30, 2012
	TUCSON ELECTRIC POWER COMPANY	Springerville Unit One Lease [Member]	Springerville Unit One Lease [Member]	Springerville Unit One Lease [Member]	Unsecured Tax Exempt Bonds [Member]	Unsecured Tax Exempt Bonds [Member]	Convertible Senior Notes [Member]
		TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	UNS Energy Corporation [Member]
Increase in Capital Lease Obligation	'	$55	$39	$39	'	'	'
Increase in Utility Plant under Capital Lease	'	55	39	39	'	'	'
Debt Instrument, Face Amount	'	'	'	'	91	193	'
Dividends	30	'	'	'	'	'	'
Debt Conversion, Converted Instrument, Amount	'	'	'	'	'	'	147
Debt Conversion, Original Debt, Amount	'	'	'	'	'	'	$150

FAIR_VALUE_MEASUREMENTS_DERIVA2

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments (Detail) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Liabilities:	'	'
Long-Term Debt	($1,505,536,000)	($1,498,442,000)
TUCSON ELECTRIC POWER COMPANY	'	'
Liabilities:	'	'
Long-Term Debt	-1,223,536,000	-1,223,442,000
Carrying Value [Member] | Level 2 [Member]	'	'
Liabilities:	'	'
Long-Term Debt	-1,506,000,000	-1,498,000,000
Carrying Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Assets:	'	'
TEP Investment in Lease Debt	0	9,000,000
Liabilities:	'	'
Long-Term Debt	-1,224,000,000	-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	-1,522,000,000	-1,583,000,000
Fair Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Assets:	'	'
TEP Investment in Lease Debt	0	9,000,000
Liabilities:	'	'
Long-Term Debt	-1,215,000,000	-1,271,000,000
Fair Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Assets:	'	'
TEP Investment in Lease Equity	$24,000,000	$23,000,000

FAIR_VALUE_MEASUREMENTS_DERIVA3

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Schedule of Fair Value Measurements of Financial Assets and Liabilities (Detail) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'		'
Cash Equivalent	$31	[1]	$20	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	21	[2]	19	[2]
Energy Contracts	2	[3]	7	[3]
Total Assets	56		53
Liabilities	'		'
Total Liabilities	-20		-27
Fair Value, Net Asset (Liability)	36		26
Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	11	[3]	15	[3]
Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	2	[3]
Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	8	[4]	10	[4]
TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	15	[1]	1	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	21	[2]	19	[2]
Energy Contracts	1	[3]	3	[3]
Total Assets	39		30
Liabilities	'		'
Total Liabilities	-12		-15
Fair Value, Net Asset (Liability)	27		15
TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	3	[3]	3	[3]
TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	2	[3]
TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	8	[4]	10	[4]
Level 1 [Member]	'		'
Assets	'		'
Cash Equivalent	31	[1]	20	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	0	[3]
Total Assets	33		27
Liabilities	'		'
Total Liabilities	0		0
Fair Value, Net Asset (Liability)	33		27
Level 1 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	15	[1]	1	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	0	[3]
Total Assets	17		8
Liabilities	'		'
Total Liabilities	0		0
Fair Value, Net Asset (Liability)	17		8
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Level 2 [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	21	[2]	19	[2]
Energy Contracts	1	[3]	2	[3]
Total Assets	22		21
Liabilities	'		'
Total Liabilities	-13		-17
Fair Value, Net Asset (Liability)	9		4
Level 2 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	5	[3]	7	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	8	[4]	10	[4]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	21	[2]	19	[2]
Energy Contracts	1	[3]	1	[3]
Total Assets	22		20
Liabilities	'		'
Total Liabilities	-10		-13
Fair Value, Net Asset (Liability)	12		7
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	3	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	8	[4]	10	[4]
Level 3 [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	1	[3]	5	[3]
Total Assets	1		5
Liabilities	'		'
Total Liabilities	-7		-10
Fair Value, Net Asset (Liability)	-6		-5
Level 3 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6	[3]	8	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	2	[3]
Level 3 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	2	[3]
Total Assets	0		2
Liabilities	'		'
Total Liabilities	-2		-2
Fair Value, Net Asset (Liability)	-2		0
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	0	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	2	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Netting [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash(1)	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	-2	[3],[5]	-5	[3],[5]
Total Assets	-2	[5]	-5	[5]
Liabilities	'		'
Total Liabilities	2	[5]	5	[5]
Fair Value, Net Asset (Liability)	0	[5]	0	[5]
Netting [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-2	[3],[5]	-5	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4],[5]	0	[4],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash(1)	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	-1	[3],[5]	-1	[3],[5]
Total Assets	-1	[5]	-1	[5]
Liabilities	'		'
Total Liabilities	1	[5]	1	[5]
Fair Value, Net Asset (Liability)	0	[5]	0	[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-1	[3],[5]	-1	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3],[5]	0	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4],[5]	0	[4],[5]
Net Fair Value [Member]	'		'
Assets	'		'
Cash Equivalent	31	[1]	20	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	21	[2]	19	[2]
Energy Contracts	0	[3]	2	[3]
Total Assets	54		48
Liabilities	'		'
Total Liabilities	-18		-22
Fair Value, Net Asset (Liability)	36		26
Net Fair Value [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[3]	10	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	2	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	8	[4]	10	[4]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	15	[1]	1	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	21	[2]	19	[2]
Energy Contracts	0	[3]	2	[3]
Total Assets	38		29
Liabilities	'		'
Total Liabilities	-11		-14
Fair Value, Net Asset (Liability)	27		15
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	2	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$8	[4]	$10	[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), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below. (4)Interest R
[4]	Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index 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_DERIVA4

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Cash Flow Hedges (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Cash Flow Hedges [Abstract]	'
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	($4)

FAIR_VALUE_MEASUREMENTS_DERIVA5

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Financial Impact of Energy Contracts (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Increase (Decrease) to Regulatory Assets/Liabilities	$1	($12)	$0	($20)
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Increase (Decrease) to Regulatory Assets/Liabilities	$1	($6)	$2	($7)

FAIR_VALUE_MEASUREMENTS_DERIVA6

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Derivative Volumes (Details)	Sep. 30, 2013	Dec. 31, 2012
	GWh	GWh
Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Gas Swaps	1,819	2,228
Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Gas Swaps	29,022	17,851
TUCSON ELECTRIC POWER COMPANY | Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Gas Swaps	856	820
TUCSON ELECTRIC POWER COMPANY | Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Gas Swaps	8,504	7,958

FAIR_VALUE_MEASUREMENTS_DERIVA7

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Quantitative Information Regarding Unobservable Inputs (Detail) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	$2	[1]	$7	[1]
Total Liabilities	-20		-27
Level 3 [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	1	[1]	5	[1]
Total Liabilities	-7		-10
Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	1		'
Total Liabilities	7	[2]	'
Minimum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Unobservable Inputs: Market Price Per MWh	23		'
Maximum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Unobservable Inputs: Market Price Per MWh	48		'
TUCSON ELECTRIC POWER COMPANY	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	1	[1]	3	[1]
Total Liabilities	-12		-15
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	0	[1]	2	[1]
Total Liabilities	-2		-2
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Total Liabilities	($2)	[2]	'
[1]	Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below. (4)Interest R
[2]	) TEP comprises $2 million of the forward contract liabilitie

FAIR_VALUE_MEASUREMENTS_DERIVA8

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities (Detail) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'	'	'	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	$0.50	'	'	'	'	'	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	-6	-6	-6	-6	-5	-5	-7	-10
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'	'	'	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	-3	0	-4	-4	'	'	'	'
Settlements	2	1	3	8	'	'	'	'
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	-2	0	-5	-1	'	'	'	'
TUCSON ELECTRIC POWER COMPANY	'	'	'	'	'	'	'	'
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'	'	'	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	0.5	'	'	'	'	'	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	-2	0	-2	0	-1	0	-1	0
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'	'	'	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	-1	1	-2	0	'	'	'	'
Settlements	0	0	0	0	'	'	'	'
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	$0	$0	($1)	$0	'	'	'	'

FAIR_VALUE_MEASUREMENTS_DERIVA9

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Credit Risk (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Total Liabilities	$20	$27
Derivative, Net Liability Position, Aggregate Fair Value	-35	'
Additional Collateral, Aggregate Fair Value	35	'
Impact Of Credit Risk On Fair Value Of Derivatives	0.5	0.5
TUCSON ELECTRIC POWER COMPANY	'	'
Derivative [Line Items]	'	'
Total Liabilities	12	15
Derivative, Net Liability Position, Aggregate Fair Value	-13	'
Additional Collateral, Aggregate Fair Value	($13)	'

CHANGES_IN_ACCUMULATED_OTHER_C2

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT CHANGES IN ACCUMULATIVE OTHER COMPREHENSIVE INCOME BY COMPONENT (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Gains and Losses on Cash Flow Hedges	'	'	'	'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	($601)	'	($1,420)	'
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	917	'	2,173	'
Amortization of SERP and Defined Benefit Plans	'	'	'	'
Prior Service Costs	-110	'	-332	'
Tax (Expense) Benefit	42	34	127	50
Amortization, Net of Taxes	-68	-55	-205	-219
Total Reclassification from Other Comprehensive Income for the Period	-985	'	-2,378	'
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Gains and Losses on Cash Flow Hedges	'	'	'	'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	-579	'	-1,360	'
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	885	'	2,078	'
Amortization of SERP and Defined Benefit Plans	'	'	'	'
Prior Service Costs	-110	'	-332	'
Tax (Expense) Benefit	42	34	127	50
Amortization, Net of Taxes	-68	-55	-205	-219
Total Reclassification from Other Comprehensive Income for the Period	-953	'	-2,283	'
Interest Rate Contract Long Term Debt [Member]	'	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-350	'	-1,026	'
Interest Rate Contract Long Term Debt [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-296	'	-871	'
Interest Rate contract Capital Leases [Member]	'	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-612	'	-1,820	'
Interest Rate contract Capital Leases [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-612	'	-1,820	'
Commodity Contract [Member]	'	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-556	'	-747	'
Commodity Contract [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	($556)	'	($747)	'

POTENTIAL_PURCHASE_OF_GASFIRED1

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY (Details) (Potential Purchase of Gas-Fired Generation Facility [Member])	Sep. 30, 2013
	MW
TUCSON ELECTRIC POWER COMPANY	'
Unusual or Infrequent Item [Line Items]	'
Generating Capacity of Plant in MW	550
UNS ELECTRIC, INC. [Member]	'
Unusual or Infrequent Item [Line Items]	'
Generating Capacity of Plant in MW	150