Tucson Electric Power 10-K 25 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'UNS	'	'
Entity Registrant Name	'UNS Energy Corp	'	'
Entity Central Index Key	'0000941138	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filer	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	41,633,535	'
Entity Public Float	'	'	$1,855,552,035
TUCSON ELECTRIC POWER COMPANY	'	'	'
Entity Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Entity Registrant Name	'TUCSON ELECTRIC POWER COMPANY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filer	'No	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	32,139,434	'

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues	'	'	'
Electric Retail Sales	$1,102,769	$1,087,279	$1,085,822
Electric Wholesale Sales	135,160	125,414	132,346
Gas Retail Sales	125,478	123,133	145,053
Other Revenue	121,153	125,940	115,481
Total Operating Revenues	1,484,560	1,461,766	1,478,702
Operating Expenses	'	'	'
Fuel	332,279	327,832	324,520
Purchased Energy	252,532	224,696	276,610
Transmission and Other PPFAC Recoverable Costs	23,012	14,540	7,334
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	-16,313	32,246	-4,932
Total Fuel and Purchased Energy	591,510	599,314	603,532
Operations and Maintenance	389,699	383,689	379,220
Depreciation	149,615	141,303	133,832
Amortization	27,557	35,784	30,983
Taxes Other Than Income Taxes	54,683	49,881	49,428
Total Operating Expenses	1,213,064	1,209,971	1,196,995
Operating Income	271,496	251,795	281,707
Other Income (Deductions)	'	'	'
Interest Income	534	1,106	4,568
Other Income	7,880	4,928	7,958
Other Expense	-3,463	-7,723	-5,278
Appreciation in Fair Value of Investments	2,833	1,892	329
Total Other Income (Deductions)	7,784	203	7,577
Interest Expense [Abstract]	'	'	'
Long-Term Debt	71,180	71,909	73,217
Capital Leases	25,140	33,613	40,359
Other Interest Expense	538	1,983	2,535
Interest Capitalized	-3,483	-2,153	-3,753
Interest Expense	93,375	105,352	112,358
Income Before Income Taxes	185,905	146,646	176,926
Income Tax Expense (Benefit)	58,427	55,727	66,951
Net Income	127,478	90,919	109,975
Weighted-Average Shares of Common Stock Outstanding (000)	'	'	'
Basic (in shares)	41,618	40,362	36,962
Diluted (in shares)	41,975	41,755	41,609
Earnings Per Share	'	'	'
Basic (in dollars per share)	$3.06	$2.25	$2.98
Diluted (in dollars per share)	$3.04	$2.20	$2.75
Dividends Declared Per Share (usd per share)	$1.74	$1.72	$1.68
TUCSON ELECTRIC POWER COMPANY	'	'	'
Operating Revenues	'	'	'
Electric Retail Sales	934,357	915,879	903,930
Electric Wholesale Sales	132,500	111,194	129,861
Other Revenue	129,833	134,587	122,595
Total Operating Revenues	1,196,690	1,161,660	1,156,386
Operating Expenses	'	'	'
Fuel	325,903	318,901	318,268
Purchased Energy	112,452	80,137	105,766
Transmission and Other PPFAC Recoverable Costs	12,233	5,722	-1,435
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	-12,458	31,113	-6,165
Total Fuel and Purchased Energy	438,130	435,873	416,434
Operations and Maintenance	335,321	334,553	330,801
Depreciation	118,076	110,931	104,894
Amortization	31,294	39,493	34,650
Taxes Other Than Income Taxes	43,498	40,323	40,199
Total Operating Expenses	966,319	961,173	926,978
Operating Income	230,371	200,487	229,408
Other Income (Deductions)	'	'	'
Interest Income	120	136	3,567
Other Income	5,770	3,953	5,364
Other Expense	-10,715	-13,574	-12,064
Appreciation in Fair Value of Investments	2,833	1,892	329
Total Other Income (Deductions)	-1,992	-7,593	-2,804
Interest Expense [Abstract]	'	'	'
Long-Term Debt	56,378	55,038	49,858
Capital Leases	25,140	33,613	40,358
Other Interest Expense	87	1,446	1,127
Interest Capitalized	-2,554	-1,782	-2,073
Interest Expense	79,051	88,315	89,270
Income Before Income Taxes	149,328	104,579	137,334
Income Tax Expense (Benefit)	47,986	39,109	52,000
Net Income	$101,342	$65,470	$85,334

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities	'	'	'
Cash Receipts from Electric Retail Sales	$1,208,967,000	$1,197,390,000	$1,163,537,000
Cash Receipts from Electric Wholesale Sales	160,947,000	149,722,000	183,151,000
Cash Receipts from Gas Retail Sales	138,775,000	141,590,000	159,529,000
Cash Receipts from Operating Springerville Units 3 & 4	114,258,000	107,927,000	104,754,000
Cash Receipts from Gas Wholesale Sales	3,740,000	5,233,000	12,404,000
Interest Received	517,000	2,947,000	6,334,000
Income Tax Refunds Received	11,000	1,821,000	4,672,000
Performance Deposits Received	0	200,000	7,050,000
Other Cash Receipts	35,142,000	24,105,000	23,937,000
Fuel Costs Paid	-285,812,000	-321,355,000	-277,386,000
Purchased Energy Costs Paid	-280,920,000	-250,231,000	-328,713,000
Payment of Operations and Maintenance Costs	-260,453,000	-291,512,000	-295,662,000
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	-182,488,000	-187,257,000	-179,766,000
Wages Paid, Net of Amounts Capitalized	-131,710,000	-127,176,000	-122,370,000
Interest Paid, Net of Amounts Capitalized	-66,610,000	-69,478,000	-68,027,000
Capital Lease Interest Paid	-22,553,000	-28,788,000	-32,103,000
Income Taxes Paid	-316,000	0	-700,000
Performance Deposits Paid	0	-200,000	-4,550,000
Wholesale Gas Costs Paid	0	0	-11,822,000
Other Cash Payments	-10,983,000	-6,829,000	-6,949,000
Net Cash Flows—Operating Activities	420,512,000	348,109,000	337,320,000
Cash Flows from Investing Activities	'	'	'
Capital Expenditures	-325,886,000	-307,277,000	-374,122,000
Purchase of Intangibles—Renewable Energy Credits	-26,948,000	-10,317,000	-5,992,000
Return of Investments in Springerville Lease Debt	9,104,000	19,278,000	38,353,000
Change in Restricted Cash	4,134,000	-1,445,000	0
Proceeds from Note Receivable	0	15,000,000	0
Other, net	5,786,000	21,862,000	14,673,000
Net Cash Flows—Investing Activities	-333,810,000	-262,899,000	-327,088,000
Cash Flows from Financing Activities	'	'	'
Proceeds from Borrowings Under Revolving Credit Facilities	139,000,000	359,000,000	391,000,000
Repayments of Borrowings Under Revolving Credit Facilities	-108,000,000	-381,000,000	-351,000,000
Payments of Capital Lease Obligations	-99,621,000	-89,452,000	-74,381,000
Common Stock Dividends Paid	-72,234,000	-69,648,000	-61,904,000
Proceeds from Stock Options Exercised	3,831,000	3,570,000	8,115,000
Proceeds from Common Stock Issuance	464,000	0	0
Proceeds from Issuance of Long-Term Debt	0	149,513,000	340,285,000
Repayments of Long-Term Debt	0	-9,341,000	-252,125,000
Equity Investment from UNS Energy	0	0	30,000,000
Other, net	818,000	-324,000	-1,431,000
Net Cash Provided by (Used in) Financing Activities	-135,742,000	-37,682,000	-1,441,000
Cash and Cash Equivalents, Period Increase (Decrease)	-49,040,000	47,528,000	8,791,000
Cash and Cash Equivalents, Beginning of Period	123,918,000	76,390,000	67,599,000
Cash and Cash Equivalents, End of Period	74,878,000	123,918,000	76,390,000
TUCSON ELECTRIC POWER COMPANY	'	'	'
Cash Flows from Operating Activities	'	'	'
Cash Receipts from Electric Retail Sales	1,020,903,000	1,006,926,000	963,247,000
Cash Receipts from Electric Wholesale Sales	146,880,000	124,594,000	152,618,000
Cash Receipts from Operating Springerville Units 3 & 4	114,258,000	107,927,000	104,754,000
Reimbursement of Affiliate Charges	23,468,000	20,926,000	18,448,000
Cash Receipts from Gas Wholesale Sales	3,271,000	4,652,000	11,825,000
Interest Received	509,000	2,025,000	5,367,000
Income Tax Refunds Received	77,000	493,000	7,492,000
Other Cash Receipts	25,079,000	18,850,000	19,611,000
Fuel Costs Paid	-280,639,000	-313,742,000	-271,975,000
Payment of Operations and Maintenance Costs	-253,054,000	-282,752,000	-287,615,000
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	-144,849,000	-147,859,000	-139,728,000
Purchased Power Costs Paid	-115,008,000	-81,328,000	-117,224,000
Wages Paid, Net of Amounts Capitalized	-110,995,000	-104,955,000	-100,942,000
Interest Paid, Net of Amounts Capitalized	-52,589,000	-52,125,000	-45,433,000
Capital Lease Interest Paid	-22,553,000	-28,786,000	-32,103,000
Income Taxes Paid	0	-1,796,000	-2,346,000
Wholesale Gas Costs Paid	0	0	-11,822,000
Other Cash Payments	-8,567,000	-5,131,000	-5,880,000
Net Cash Flows—Operating Activities	346,191,000	267,919,000	268,294,000
Cash Flows from Investing Activities	'	'	'
Capital Expenditures	-252,848,000	-252,782,000	-351,890,000
Purchase of Intangibles—Renewable Energy Credits	-23,280,000	-8,889,000	-5,111,000
Return of Investments in Springerville Lease Debt	9,104,000	19,278,000	38,353,000
Change in Restricted Cash	4,134,000	-1,445,000	0
Other, net	3,228,000	15,957,000	6,637,000
Net Cash Flows—Investing Activities	-259,662,000	-227,881,000	-312,011,000
Cash Flows from Financing Activities	'	'	'
Proceeds from Borrowings Under Revolving Credit Facilities	78,000,000	189,000,000	220,000,000
Repayments of Borrowings Under Revolving Credit Facilities	-78,000,000	-199,000,000	-210,000,000
Payments of Capital Lease Obligations	-99,621,000	-89,452,000	-74,343,000
Dividends Paid to UNS Energy	-40,000,000	-30,000,000	0
Proceeds from Issuance of Long-Term Debt	0	149,513,000	260,285,000
Repayments of Long-Term Debt	0	-6,535,000	-172,460,000
Equity Investment from UNS Energy	0	0	30,000,000
Other, net	-1,316,000	-1,539,000	-2,030,000
Net Cash Provided by (Used in) Financing Activities	-140,937,000	11,987,000	51,452,000
Cash and Cash Equivalents, Period Increase (Decrease)	-54,408,000	52,025,000	7,735,000
Cash and Cash Equivalents, Beginning of Period	79,743,000	27,718,000	19,983,000
Cash and Cash Equivalents, End of Period	$25,335,000	$79,743,000	$27,718,000

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Income	$127,478	$90,919	$109,975
Other Comprehensive Income (Loss)	'	'	'
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit	2,825	1,134	-1,473
SERP Benefit Amortization, net of income tax (expense) benefit	916	-840	1,158
Total Other Comprehensive Income (Loss), Net of Tax	3,741	294	-315
Total Comprehensive Income	131,219	91,213	109,660
TUCSON ELECTRIC POWER COMPANY	'	'	'
Net Income	101,342	65,470	85,334
Other Comprehensive Income (Loss)	'	'	'
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit	2,738	1,354	-1,433
SERP Benefit Amortization, net of income tax (expense) benefit	916	-840	1,158
Total Other Comprehensive Income (Loss), Net of Tax	3,654	514	-275
Total Comprehensive Income	$104,996	$65,984	$85,059

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	($1,850)	($743)	$964
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	-572	608	-804
TUCSON ELECTRIC POWER COMPANY	'	'	'
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	-1,793	-887	941
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	($572)	$608	($804)

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Utility Plant	'	'
Plant in Service	$5,192,122	$5,005,768
Utility Plant Under Capital Leases	637,957	582,669
Construction Work in Progress	201,959	128,621
Total Utility Plant	6,032,038	5,717,058
Less Accumulated Depreciation and Amortization	-1,982,524	-1,921,733
Less Accumulated Amortization of Capital Lease Assets	-514,677	-494,962
Total Utility Plant—Net	3,534,837	3,300,363
Investments And Other Property	'	'
Investments in Lease Equity	36,194	36,339
Other	34,971	36,537
Total Investments and Other Property	71,165	72,876
Current Assets	'	'
Cash and Cash Equivalents	74,878	123,918
Accounts Receivable—Customer	104,596	93,742
Unbilled Accounts Receivable	52,403	53,568
Allowance for Doubtful Accounts	-6,833	-6,545
Materials and Supplies	88,085	93,322
Deferred Income Taxes—Current	59,681	34,260
Fuel Inventory	44,317	62,019
Regulatory Assets—Current	52,763	51,619
Derivative Instruments	5,629	3,165
Investments in Lease Debt	0	9,118
Other	15,354	33,567
Total Current Assets	490,873	551,753
Regulatory and Other Assets	'	'
Regulatory Assets—Noncurrent	150,584	191,077
Derivative Instruments	1,180	3,801
Other Assets	24,430	20,559
Total Regulatory and Other Assets	176,194	215,437
Total Assets	4,273,069	4,140,429
Capitalization	'	'
Common Stock Equity	1,130,784	1,065,465
Capital Lease Obligations	149,767	262,138
Long-Term Debt	1,507,070	1,498,442
Long-term Debt	1,507,070	1,498,442
Total Capitalization	2,787,621	2,826,045
Current Liabilities	'	'
Current Obligations Under Capital Leases	167,659	90,583
Borrowings Under Revolving Credit Facilities	22,000	0
Accounts Payable—Trade	117,503	107,740
Regulatory Liabilities—Current	53,935	43,516
Accrued Taxes Other than Income Taxes	43,880	41,939
Customer Deposits	30,671	34,048
Accrued Employee Expenses	28,148	24,094
Accrued Interest	27,786	31,950
Derivative Instruments	7,534	14,742
Other	17,775	10,517
Total Current Liabilities	516,891	399,129
Deferred Credits and Other Liabilities	'	'
Deferred Income Taxes—Noncurrent	481,662	364,756
Regulatory Liabilities—Noncurrent	302,482	279,111
Pension and Other Retiree Benefits	90,923	159,401
Derivative Instruments	7,100	12,709
Other	86,390	99,278
Total Deferred Credits and Other Liabilities	968,557	915,255
Commitments, Contingencies, and Environmental Matters	'	'
Total Capitalization and Other Liabilities	4,273,069	4,140,429
TUCSON ELECTRIC POWER COMPANY	'	'
Utility Plant	'	'
Plant in Service	4,467,667	4,348,041
Utility Plant Under Capital Leases	637,957	582,669
Construction Work in Progress	180,485	98,460
Total Utility Plant	5,286,109	5,029,170
Less Accumulated Depreciation and Amortization	-1,826,977	-1,783,787
Less Accumulated Amortization of Capital Lease Assets	-514,677	-494,962
Total Utility Plant—Net	2,944,455	2,750,421
Investments And Other Property	'	'
Investments in Lease Equity	36,194	36,339
Other	33,488	35,091
Total Investments and Other Property	69,682	71,430
Current Assets	'	'
Cash and Cash Equivalents	25,335	79,743
Accounts Receivable—Customer	80,211	71,813
Unbilled Accounts Receivable	34,369	33,782
Allowance for Doubtful Accounts	-4,825	-4,598
Accounts Receivable - Due from Affiliates	6,064	5,720
Materials and Supplies	75,200	80,377
Deferred Income Taxes—Current	63,497	37,212
Fuel Inventory	44,027	61,737
Regulatory Assets—Current	42,555	34,345
Derivative Instruments	2,137	2,230
Investments in Lease Debt	0	9,118
Other	12,923	32,163
Total Current Assets	381,493	443,642
Regulatory and Other Assets	'	'
Regulatory Assets—Noncurrent	141,030	178,330
Derivative Instruments	167	1,354
Other Assets	19,233	15,869
Total Regulatory and Other Assets	160,430	195,553
Total Assets	3,556,060	3,461,046
Capitalization	'	'
Common Stock Equity	925,923	860,927
Capital Lease Obligations	149,767	262,138
Long-Term Debt	1,223,070	'
Long-term Debt	1,223,070	1,223,442
Total Capitalization	2,298,760	2,346,507
Current Liabilities	'	'
Current Obligations Under Capital Leases	167,659	90,583
Accounts Payable—Trade	88,556	82,122
Regulatory Liabilities—Current	23,701	20,822
Accounts Payable—Due to Affiliates	9,153	3,134
Accrued Taxes Other than Income Taxes	34,485	33,060
Customer Deposits	21,354	24,846
Accrued Employee Expenses	24,454	20,715
Accrued Interest	22,785	26,965
Derivative Instruments	5,531	4,899
Other	9,244	7,085
Total Current Liabilities	406,922	314,231
Deferred Credits and Other Liabilities	'	'
Deferred Income Taxes—Noncurrent	420,878	319,216
Regulatory Liabilities—Noncurrent	263,270	241,189
Pension and Other Retiree Benefits	84,936	149,718
Derivative Instruments	5,161	10,565
Other	76,133	79,620
Total Deferred Credits and Other Liabilities	850,378	800,308
Commitments, Contingencies, and Environmental Matters	'	'
Total Capitalization and Other Liabilities	$3,556,060	$3,461,046

CONSOLIDATED_STATEMENTS_OF_CAP

CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Common Stock, Shares Authorized	75,000,000	75,000,000
Common Stock, Shares, Outstanding	41,538,343	41,343,851
COMMON STOCK EQUITY	'	'
Common Stock-No Par Value	$889,301	$882,138
Accumulated Deficit	247,532	193,117
Accumulated Other Comprehensive Loss	-6,049	-9,790
Total Common Stock Equity	1,130,784	1,065,465
PREFERRED STOCK	'	'
No Par Value, 1,000,000 Shares Authorized, None Outstanding	0	0
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	317,426	352,721
Less Current Maturities	-167,659	-90,583
Total Long-Term Capital Lease Obligations	149,767	262,138
LONG-TERM DEBT	'	'
Long-term Debt	1,507,070	1,498,442
Total Capitalization	2,787,621	2,826,045
Springerville Unit 1 [Member]	'	'
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	192,871	196,843
Springerville Coal Handling Facilities [Member]	'	'
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	27,878	48,038
Springerville Common Facilities [Member]	'	'
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	96,677	107,840
Parent [Member] | Line of Credit [Member]	'	'
LONG-TERM DEBT	'	'
Long-term Debt	54,000	45,000
TUCSON ELECTRIC POWER COMPANY	'	'
Common Stock, Shares Authorized	75,000,000	75,000,000
Common Stock, Shares, Outstanding	32,139,434	32,139,434
COMMON STOCK EQUITY	'	'
Common Stock-No Par Value	888,971	888,971
Capital Stock Expense	-6,357	-6,357
Accumulated Deficit	49,185	-12,157
Accumulated Other Comprehensive Loss	-5,876	-9,530
Total Common Stock Equity	925,923	860,927
PREFERRED STOCK	'	'
No Par Value, 1,000,000 Shares Authorized, None Outstanding	0	0
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	317,426	352,721
Less Current Maturities	-167,659	-90,583
Total Long-Term Capital Lease Obligations	149,767	262,138
LONG-TERM DEBT	'	'
Long-term Debt	1,223,070	1,223,442
Total Capitalization	2,298,760	2,346,507
TUCSON ELECTRIC POWER COMPANY | Springerville Unit 1 [Member]	'	'
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	192,871	196,843
TUCSON ELECTRIC POWER COMPANY | Springerville Coal Handling Facilities [Member]	'	'
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	27,878	48,038
TUCSON ELECTRIC POWER COMPANY | Springerville Common Facilities [Member]	'	'
CAPITAL LEASE OBLIGATIONS	'	'
Capital Lease Obligations	96,677	107,840
UNS ELECTRIC, INC.	'	'
LONG-TERM DEBT	'	'
Long-term Debt	130	'
Unsecured Fixed Rate Bonds [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
LONG-TERM DEBT	'	'
Long-term Debt	1,008,268	1,008,142
Variable Rate Tax-Exempt Bonds [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
LONG-TERM DEBT	'	'
Long-term Debt	214,802	215,300
Unsecured Debt [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
LONG-TERM DEBT	'	'
Long-term Debt	1,008,268	1,008,142
Unsecured Debt [Member] | UNS Gas and UNS Electric [Member]	'	'
LONG-TERM DEBT	'	'
Long-term Debt	200,000	200,000
Uns Electric Term Loan [Member] | UNS ELECTRIC, INC.	'	'
LONG-TERM DEBT	'	'
Long-term Debt	$30,000	$30,000
Minimum [Member] | Unsecured Debt [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
LONG-TERM DEBT	'	'
Fixed interest rate of Long-Term Debt	3.85%	'
Minimum [Member] | Unsecured Debt [Member] | UNS Gas and UNS Electric [Member]	'	'
LONG-TERM DEBT	'	'
Fixed interest rate of Long-Term Debt	5.39%	'
Maximum [Member] | Unsecured Debt [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
LONG-TERM DEBT	'	'
Fixed interest rate of Long-Term Debt	5.75%	'
Maximum [Member] | Unsecured Debt [Member] | UNS Gas and UNS Electric [Member]	'	'
LONG-TERM DEBT	'	'
Fixed interest rate of Long-Term Debt	7.10%	'

CONSOLIDATED_STATEMENTS_OF_CAP1

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	75,000,000	75,000,000
Shares Outstanding, common stock	41,538,343	41,343,851
Shares Authorized, preferred stock	1,000,000	1,000,000
Shares Outstanding, preferred stock	0	0
Par Value, preferred stock	$0	$0
TUCSON ELECTRIC POWER COMPANY	'	'
Common Stock, Shares Authorized	75,000,000	75,000,000
Shares Outstanding, common stock	32,139,434	32,139,434

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	TUCSON ELECTRIC POWER COMPANY	Common Shares Outstanding [Member]	Common Stock [Member]	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Accumulated Other Comprehensive Loss [Member]
Share data in Thousands, unless otherwise specified	USD ($)	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, 2010	$830,756,000	$709,884,000	'	$715,687,000	$858,971,000	($6,357,000)	$124,838,000	($132,961,000)	($9,769,000)	($9,769,000)
Balances, shares at Dec. 31, 2010	'	'	36,542	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	109,975,000	85,334,000	'	'	'	'	109,975,000	85,334,000	'	'
Other Comprehensive Loss, net of tax	-315,000	-275,000	'	'	'	'	'	'	-315,000	-275,000
Dividends Paid to UNS Energy	'	0	'	'	'	'	'	'	'	'
Dividends Declared	-62,158,000	'	'	'	'	'	-62,158,000	'	'	'
Shares Issued for Stock Options, shares	319	'	319	'	'	'	'	'	'	'
Shares Issued for Stock Options	8,176,000	'	'	8,176,000	'	'	'	'	'	'
Shares Issued Under Performance Share Awards, shares	'	'	57	'	'	'	'	'	'	'
Shares Issued Under Performance Share Awards	0	'	'	0	'	'	'	'	'	'
Share-based Compensation	2,040,000	'	'	2,040,000	'	'	'	'	'	'
Payments of Dividends	'	30,000,000	'	'	30,000,000	'	'	'	'	'
Balances at Dec. 31, 2011	888,474,000	824,943,000	'	725,903,000	888,971,000	-6,357,000	172,655,000	-47,627,000	-10,084,000	-10,044,000
Balances, shares at Dec. 31, 2011	'	'	36,918	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	6,476,000	-1,461,000	'	'	'	'	'	'	'	'
Balances at Mar. 31, 2012	'	'	'	'	'	'	'	'	'	'
Balances at Dec. 31, 2011	888,474,000	824,943,000	'	725,903,000	'	-6,357,000	172,655,000	-47,627,000	-10,084,000	-10,044,000
Balances, shares at Dec. 31, 2011	'	'	36,918	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	90,919,000	65,470,000	'	'	'	'	90,919,000	65,470,000	'	'
Other Comprehensive Loss, net of tax	294,000	514,000	'	'	'	'	'	'	294,000	514,000
Dividends Paid to UNS Energy	'	-30,000,000	'	'	'	'	'	-30,000,000	'	'
Dividends Declared	-70,457,000	'	'	'	'	'	-70,457,000	'	'	'
Shares Issued on Conversion of Notes and Related Tax Effect, shares	'	'	4,262	'	'	'	'	'	'	'
Shares Issued on Conversion of Notes and Related Tax Effect	149,805,000	'	'	149,805,000	'	'	'	'	'	'
Shares Issued for Stock Options, shares	132	'	133	'	'	'	'	'	'	'
Shares Issued for Stock Options	3,511,000	'	'	3,511,000	'	'	'	'	'	'
Shares Issued Under Performance Share Awards, shares	'	'	31	'	'	'	'	'	'	'
Shares Issued Under Performance Share Awards	0	'	'	0	'	'	'	'	'	'
Share-based Compensation	2,919,000	'	'	2,919,000	'	'	'	'	'	'
Balances at Dec. 31, 2012	1,065,465,000	860,927,000	'	882,138,000	888,971,000	-6,357,000	193,117,000	-12,157,000	-9,790,000	-9,530,000
Balances, shares at Dec. 31, 2012	'	'	41,344	'	'	'	'	'	'	'
Balances at Sep. 30, 2012	'	'	'	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	7,506,000	452,000	'	'	'	'	'	'	'	'
Balances at Dec. 31, 2012	1,065,465,000	860,927,000	'	'	888,971,000	-6,357,000	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	11,345,000	1,478,000	'	'	'	'	'	'	'	'
Balances at Mar. 31, 2013	'	'	'	'	'	'	'	'	'	'
Balances at Dec. 31, 2012	1,065,465,000	860,927,000	'	882,138,000	888,971,000	-6,357,000	193,117,000	-12,157,000	-9,790,000	-9,530,000
Balances, shares at Dec. 31, 2012	'	'	41,344	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	127,478,000	101,342,000	'	'	'	'	127,478,000	101,342,000	'	'
Other Comprehensive Loss, net of tax	3,741,000	3,654,000	'	'	'	'	'	'	3,741,000	3,654,000
Dividends Paid to UNS Energy	'	-40,000,000	'	'	'	'	'	-40,000,000	'	'
Dividends Declared	-73,063,000	'	'	'	'	'	-73,063,000	'	'	'
Shares Issued under Dividend Reinvestment Plan, shares	'	'	10	'	'	'	'	'	'	'
Shares Issued under Dividend Reinvestment Plan	464,000	'	'	464,000	'	'	'	'	'	'
Shares Issued for Stock Options, shares	127	'	127	'	'	'	'	'	'	'
Shares Issued for Stock Options	3,831,000	'	'	3,831,000	'	'	'	'	'	'
Shares Issued Under Performance Share Awards, shares	'	'	57	'	'	'	'	'	'	'
Shares Issued Under Performance Share Awards	0	'	'	0	'	'	'	'	'	'
Share-based Compensation	2,868,000	'	'	2,868,000	'	'	'	'	'	'
Balances at Dec. 31, 2013	1,130,784,000	925,923,000	'	889,301,000	888,971,000	-6,357,000	247,532,000	49,185,000	-6,049,000	-5,876,000
Balances, shares at Dec. 31, 2013	'	'	41,538	'	'	'	'	'	'	'
Balances at Sep. 30, 2013	'	'	'	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Net Income	13,525,000	4,910,000	'	'	'	'	'	'	'	'
Balances at Dec. 31, 2013	$1,130,784,000	$925,923,000	'	'	$888,971,000	($6,357,000)	'	'	'	'

CONSOLIDATED_STATEMENT_OF_CHAN1

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	75,000,000	75,000,000
TUCSON ELECTRIC POWER COMPANY	'	'
Common Stock, Shares Authorized	75,000,000	75,000,000

NATURE_OF_OPERATIONS_AND_SUMMA

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	NATURE OF OPERATIONS
	UNS Energy Corporation (UNS Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
	TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of December 31, 2013. TEP generates, transmits and distributes electricity to approximately 413,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).
	UES wholly-owns two regulated utilities: UNS Electric, Inc. (UNS Electric) and UNS Gas, Inc. (UNS Gas). UNS Electric is a regulated utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.
	UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2013.
	Our business is comprised of three reporting segments – TEP, UNS Electric, and UNS Gas.
	References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
	See Note 2 for information regarding a pending merger with Fortis, Inc.
	BASIS OF PRESENTATION
	UNS Energy's consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 3. The consolidated financial statements include the accounts of UNS Energy and all of its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated if recovery from ratepayers is probable. See Note 4. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income. See Note 5.
	USE OF ACCOUNTING ESTIMATES
	Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect:
	•	Assets and liabilities on our balance sheets at the dates of the financial statements;
	•	Our disclosures about contingent assets and liabilities at the dates of the financial statements; and
	•	Our revenues and expenses in our income statements during the periods presented.
	Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.
	ACCOUNTING FOR REGULATED OPERATIONS
	We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through FERC-approved transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future billing reductions.
	Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 3.
	TEP, UNS Electric, and UNS Gas apply regulatory accounting as the following conditions exist:
	•	An independent regulator sets rates;
	•	The regulator sets the rates to recover the specific enterprise’s costs of providing service; and
	•	Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.
	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 15.
	•	Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 16.
	CASH AND CASH EQUIVALENTS
	We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
	RESTRICTED CASH
	Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets. Restricted cash was $2 million at December 31, 2013 and $7 million at December 31, 2012.
	UTILITY PLANT
	Utility Plant includes the business property and equipment that supports electric and gas services, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction.
	We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statements as costs are incurred.
	When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage value. There is no income statement impact.
	AFUDC and Capitalized Interest
	AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.
	The average AFUDC rates on regulated construction expenditures are included in the table below:
		2013		2012		2011
	TEP	7.38	%	7.22	%	6.72	%
	UNS Electric	8.07	%	7.89	%	8.18	%
	UNS Gas	7.89	%	7.95	%	8.32	%
	UNS Energy did not capitalize interest related to non-regulated construction activity in 2013 or 2012. UNS Energy capitalized interest on non-regulated construction activity at a rate of 3.30% for 2011.
	Depreciation
	We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 and Note 5. The Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant:
		2013		2012		2011
	TEP	3.16	%	3.22	%	3.14	%
	UNS Electric	3.94	%	3.99	%	4.02	%
	UNS Gas	2.63	%	2.69	%	2.84	%
	TEP Utility Plant Under Capital Leases
	TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense—Capital Leases. The lease terms are described in Note 6.
	Computer Software Costs
	We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.
	INVESTMENTS IN LEASE DEBT AND EQUITY
	TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 15. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to the equity holders.
	TEP accounts for its equity interest in the Springerville Unit 1 Lease trust using the equity method.
	ASSET RETIREMENT OBLIGATIONS
	TEP and UNS Electric have identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense, and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.
	Depreciation rates for all of our utilities also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.
	EVALUATION OF ASSETS FOR IMPAIRMENT
	We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.
	DEFERRED FINANCING COSTS
We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.
OPERATING REVENUES
We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity and gas sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.
For purchased power and wholesale sales contracts that are not settled with energy, TEP and UNS Electric net the sales contracts with the purchase power contracts and reflect the net amount as Electric Wholesale Sales. The corresponding cash receipts are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales, while cash payments are recorded as Purchased Energy/Power Costs Paid.
TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned.
The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) associated with energy sales that no longer occur due to EE Standards and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions.
INVENTORY
We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.
FUEL AND PURCHASED ENERGY COST RECOVERY MECHANISMS
TEP and UNS Electric Purchased Power and Fuel Adjustment Clause
TEP and UNS Electric recover actual fuel, purchased power and transmission costs incurred to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts the PPFAC rate at which TEP and UNS Electric recover these costs. The difference between costs recovered through rates and actual fuel, purchased power and transmission costs prudently incurred to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 3.
UNS Gas Purchased Gas Adjustor
UNS Gas recovers actual gas costs incurred through a Purchased Gas Adjustor (PGA) mechanism that adjusts monthly. Gas cost over-recoveries are deferred as regulatory liabilities and under-recoveries are deferred as regulatory assets. See Note 3.
RENEWABLE ENERGY and ENERGY EFFICIENCY PROGRAMS
The ACC’s Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The utilities must file annual RES implementation plans for review and approval by the ACC. The approved cost of carrying out those plans is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates.
TEP, UNS Electric, and UNS Gas are required to implement cost-effective Demand-Side Management (DSM) programs to comply with the ACC’s Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail kWh savings equal to22% by 2020. The Gas EE Standards require increasing annual targeted retail therm sales equal to 6% by 2020.
Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP and UNS Electric recognize RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. Similarly, UNS Gas recognizes DSM surcharge revenue in Gas Retail Sales.
RENEWABLE ENERGY CREDITS
The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP or UNS Electric purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC.
When RECs are purchased, TEP and UNS Electric record the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount. See Note 3.
INCOME TAXES
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized.
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.  Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.
Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 3.
We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and are deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises.
Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.
TAXES OTHER THAN INCOME TAXES
We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies on the balance sheet for these taxes and assessments. These amounts are not reflected in the income statements.
DERIVATIVE INSTRUMENTS
We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.
Cash Flow Hedges
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. UNS Electric uses a cash flow hedge to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP and UNS Electric account for cash flow hedges as follows:
•	The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and
•	When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.
We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.
Energy Contracts - Regulatory Recovery
TEP, UNS Electric and UNS Gas are authorized to recover the prudent costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC or PGA mechanism.
Master Netting Agreements
We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.
Normal Purchases and Normal Sales
We enter into forward energy purchase and sales contracts, including call options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.
Commodity Trading
We did not engage in trading of derivative financial instruments.
PENSION AND OTHER RETIREE BENEFITS
We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees.
We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees.
Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 10.

PENDING_MERGER_WITH_FORTIS_INC

PENDING MERGER WITH FORTIS INC.	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
PENDING MERGER WITH FORTIS INC.	'
	PENDING MERGER WITH FORTIS
	On December 11, 2013, UNS Energy announced that it had entered into an agreement and plan of merger, subject to shareholder and required regulatory approvals, to be acquired by Fortis for $60.25 per share of Common Stock in cash. Following the merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Board of Directors of each of UNS Energy and Fortis Parent have approved the merger.

REGULATORY_MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
REGULATORY MATTERS	'
	REGULATORY MATTERS
	The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP, UNS Electric, and UNS Gas. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and the pending merger. The FERC regulates terms and prices of transmission services and wholesale electricity sales, and the pending merger.
	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 discontinued Nogales transmission project 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 0.1388 cents per kWh effective July 1, 2013. The credit reflects the following:
	◦	a 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 settlement with the San Juan operator related to insurance proceeds.
	•	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. In the fourth quarter of 2013, TEP recorded revenues of $2 million related to unrecovered non-fuel costs incurred during 2013.
	•	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 0.025 cents 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 of approximately $21 million to fund programs that support the ACC's Electric Energy Efficiency Standards, as well as a $2 million performance incentive.
	2013 UNS ELECTRIC RATE ORDER
	In December 2013, the ACC issued the 2013 UNS Electric Rate Order that resolved the rate case filed by UNS Electric in December 2012 which was based on a test year ended June 30, 2012. The 2013 UNS Electric Rate Order approved new rates effective January 1, 2014.
	The provisions of the 2013 UNS Electric Rate Order 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 Rate Order also includes the following cost recovery mechanisms:
	•	a 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), which will allow more timely recovery of transmission costs associated with serving retail customers.
	2012 UNS GAS RATE ORDER
	In April 2012, the ACC approved a Base Rate increase of $2.7 million, or 1.8%, and an LFCR mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the ACC’s Gas Energy Efficiency Standards (Gas EE Standards).
	The ACC approved an authorized rate of return of 8.3% on an OCRB of $183 million, and a 1.0% 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). The new rates became effective in May 2012.
	COST RECOVERY MECHANISMS
	TEP, UNS Electric, and UNS Gas have received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
	Purchased Power and Fuel Adjustment Clause
	TEP's PPFAC rate is adjusted annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period unless suspended by the ACC.
	TEP's PPFAC rate includes: 1) a forward component, under which TEP recovers or refunds differences between a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between prudently incurred actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.
	Prior to the 2013 UNS Electric Rate Order, UNS Electric’s PPFAC rate was adjusted annually each June 1st, effective for the subsequent 12-month period. As a result of the 2013 UNS Electric Rate Order, effective January 1, 2014, UNS Electric's PPFAC rate reflects a weighted 12-month rolling average of actual fuel and purchased power costs incurred by UNS Electric. The PPFAC rate adjusts monthly, but it is restricted from changing by more than 0.83 percent from the preceding month's rate. If the PPFAC deferral balance reflects an over-collection of $10 million or more on a billed-to-customer basis, UNS Electric must file for a PPFAC rate adjustment. At December 31, 2013, the PPFAC bank balance was over-collected by $14 million on a billed-to-customer basis.
	The tables below summarize TEP’s and UNS Electric’s PPFAC rates:
		TEP
		2013						2012
		July - December			January - June			April - December			January - March
		Cents per kWh
	PPFAC Rate	0.14			0.77			0.77			0.53
	Competition Transition Charge (1)	—			—			—			(0.53	)
	Net TEP PPFAC Rate	0.14			0.77			0.77			—
	(1)	TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.
		UNS Electric
		2013									2012
		September - December			June - August			January - May			June - December		January - May
		Cents per kWh
	PPFAC Rate	(0.40	)		(0.92	)		(1.44	)		(1.44	)	(0.88	)
	UNS Gas Purchased Gas Adjustor
	The PGA mechanism allows UNS Gas to adjust Retail Rates to recover fluctuations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than 15 cents per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million or more on a billed-to-customer basis.
	In October 2013, the ACC approved an increase to the existing 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 December 31, 2013 and December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.
	The PGA rate ranged from 0.4504 to 0.5280 cents per therm in 2013, and ranged from 0.5202 to 0.6501 cents per therm in 2012.
	Renewable Energy Standards
	TEP and UNS Electric are required to expand their use of renewable energy in order to meet the ACC’s RES. TEP and UNS Electric, through a customer surcharge, recover costs associated with meeting the RES. These costs include the purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates.
	In October 2013, the ACC approved TEP's 2014 RES plan and authorized a total 2014 RES budget of $40 million with $34 million to be collected through the 2014 RES funding mechanism. TEP earned returns on solar investments of $2 million in each of 2013 and 2012 and $1 million in 2011.
	In October 2013, the ACC approved UNS Electric's 2014 RES plan and authorized a total 2014 RES budget of $7 million with $6 million to be collected through the 2014 RES funding mechanism.  UNS Electric earned returns on solar investments of less than $0.5 million in 2013 and 2012. No return was earned in 2011.
	Energy Efficiency Standards
TEP, UNS Electric, and UNS Gas are required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs.
In December 2013, the ACC approved UNS Electric’s 2013-2014 energy efficiency implementation plan that included a 2014 calendar year budget of approximately $5 million to fund programs that support the ACC’s Electric EE Standards as well as a performance incentive.
In June 2013, the ACC approved the UNS Gas 2011-2012 energy efficiency implementation plan with certain modifications. The approval included an annual energy efficiency budget of approximately $2 million and a waiver of the Gas EE Standards through 2013.
Lost Fixed Cost Recovery Mechanism
The LFCR is a mechanism to recover certain non-fuel costs that would go unrecovered due to lost sales as a result of implementing ACC approved EE Standards and distributed generation targets.
In April 2012, the ACC authorized a LFCR mechanism that enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards.
In June 2013, the ACC authorized a LFCR mechanism for TEP subject to a year-over-year cap of 1% of TEP's total retail revenues. TEP expects the LFCR rate which will recover 2013 costs, to be effective on July 1, 2014, upon review by the ACC of verified lost kWh sales.
In December 2013, as part of the 2013 UNS Electric Rate Order, the ACC authorized a LFCR for UNS Electric, to be effective on July 1, 2014.
REGULATORY ASSETS AND LIABILITIES
The following tables summarize regulatory assets and liabilities:
	31-Dec-13
	TEP				UNS				UNS			UNS
					Electric				Gas			Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	20			$	—			$	—		$	20
Derivative Instruments (Note 15)	1				—				—			1
San Juan Mine Fire Cost Deferral (2)	10				—				—			10
PPFAC (2)	4				10				—			14
DSM and LFCR (2)	3				—				—			3
Other Current Regulatory Assets (3)	5				—				—			5
Total Regulatory Assets—Current	43				10				—			53
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	75				3				2			80
Income Taxes Recoverable through Future Revenues (4)	22				3				—			25
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	25				—				—			25
Discontinued Nogales Transmission Project (6)	5				—				—			5
Other Regulatory Assets (3)	14				2				—			16
Total Regulatory Assets—Noncurrent	141				8				2			151
Regulatory Liabilities—Current
PGA (2)	—				—				(15		)	(15		)
RES (2)	(22		)		(9		)		—			(31		)
Other Current Regulatory Liabilities	(2		)		(6		)		—			(8		)
Total Regulatory Liabilities—Current	(24		)		(15		)		(15		)	(54		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(254		)		(12		)		(26		)	(292		)
Income Taxes Payable through Future Rates	(5		)		—				(1		)	(6		)
Deferred Investment Tax Credit (8)	(4		)		—				—			(4		)
Total Regulatory Liabilities—Noncurrent	(263		)		(12		)		(27		)	(302		)
Total Net Regulatory Assets (Liabilities)	$	(103	)		$	(9	)		$	(40	)	$	(152	)
	31-Dec-12
	TEP				UNS				UNS			UNS
					Electric				Gas			Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	18			$	—			$	—		$	18
Derivative Instruments (Note 15)	2				6				3			11
PPFAC (2)	7				8				—			15
DSM (2)	5				—				—			5
Other Current Regulatory Assets (3)	2				—				1			3
Total Regulatory Assets—Current	34				14				4			52
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	130				5				4			139
Income Taxes Recoverable through Future Revenues (4)	8				2				—			10
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	22				—				—			22
Discontinued Nogales Transmission Project (6)	5				—				—			5
Other Regulatory Assets (3)	13				1				1			15
Total Regulatory Assets—Noncurrent	178				8				5			191
Regulatory Liabilities—Current
PGA (2)	—				—				(17		)	(17		)
RES (2)	(19		)		(4		)		—			(23		)
Other Current Regulatory Liabilities	(2		)		(1		)		(1		)	(4		)
Total Regulatory Liabilities—Current	(21		)		(5		)		(18		)	(44		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(231		)		(11		)		(25		)	(267		)
Income Taxes Payable through Future Rates	(5		)		—				(1		)	(6		)
Deferred Investment Tax Credit (8)	(5		)		—				—			(5		)
Other Regulatory Liabilities	—				(1		)		—			(1		)
Total Regulatory Liabilities—Noncurrent	(241		)		(12		)		(26		)	(279		)
Total Net Regulatory Assets (Liabilities)	$	(50	)		$	5			$	(35	)	$	(80	)
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets below. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets.
(1)	Property Tax is recovered over approximately a six-month period as costs are paid, rather than as costs are accrued.
(2)	See Cost Recovery Mechanisms discussion above.
(3)	TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).
(4)	Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.
(5)	Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
(6)	TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.
Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers, as described below:
(7)	Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.
(8)	The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.
IMPACTS OF REGULATORY ACCOUNTING
If we determine that we no longer meet the criteria for continued application of regulatory accounting, we would be required to write off our regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on our financial statements.

BUSINESS_SEGMENTS

BUSINESS SEGMENTS	12 Months Ended
	Dec. 31, 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 Electric, a regulated electric utility
	-3	UNS Gas, a regulated gas distribution utility
	We disclose selected financial data for our reportable segments in the following tables:
		Reportable Segments
		TEP			UNS Electric			UNS Gas			Other (2)			Reconciling			UNS
														Adjustments			Energy
		Millions of Dollars
	2013
	Income Statement
	Operating Revenues-External	$	1,180		$	174		$	131		$	2		$	(2	)	$	1,485
	Operating Revenues-Intersegment (1)	17			2			3			17			(39		)	—
	Depreciation and Amortization	149			19			9			—			—			177
	Interest Income	—			1			—			—			—			1
	Interest Expense	79			7			6			1			—			93
	Income Tax Expense	48			7			7			(4		)	—			58
	Net Income	101			12			11			3			—			127
	Cash Flow Statement
	Capital Expenditures	(253		)	(56		)	(17		)	—			—			(326		)
	Balance Sheet
	Total Assets	3,556			404			311			1,194			(1,192		)	4,273
		Reportable Segments
		TEP			UNS Electric			UNS Gas			Other (2)			Reconciling			UNS
														Adjustments			Energy
		Millions of Dollars
	2012
	Income Statement
	Operating Revenues-External	$	1,145		$	189		$	129		$	—		$	(1	)	$	1,462
	Operating Revenues-Intersegment (1)	17			1			4			18			(40		)	—
	Depreciation and Amortization	150			18			9			—			—			177
	Interest Income	—			—			—			1			—			1
	Interest Expense	88			8			6			3			—			105
	Income Tax Expense	39			11			6			—			—			56
	Net Income	65			17			9			—			—			91
	Cash Flow Statement
	Capital Expenditures	(253		)	(38		)	(16		)	—			—			(307		)
	Balance Sheet
	Total Assets	3,461			370			310			1,121			(1,122		)	4,140
	2011
	Income Statement
	Operating Revenues-External	$	1,141		$	188		$	149		$	—		$	1		$	1,479
	Operating Revenue-Intersegment (1)	15			2			2			23			(42		)	—
	Depreciation and Amortization	140			17			8			1			(1		)	165
	Interest Income	4			—			—			1			—			5
	Interest Expense	89			7			7			9			—			112
	Income Tax Expense	52			11			7			(1		)	(2		)	67
	Net Income	85			18			10			—			(3		)	110
	Cash Flow Statement
	Capital Expenditures	(352		)	(96		)	(13		)	(34		)	121			(374		)
	(1)	Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.
	(2)	Other includes the UNS Energy and UES holding companies, Millennium, and UED.

UTILITY_PLANT_AND_JOINTLYOWNED

UTILITY PLANT AND JOINTLY-OWNED FACILITIES	12 Months Ended
	Dec. 31, 2013
Regulatory Operations [Abstract]	'
UTILITY PLANT AND JOINTLY-OWNED FACILITES	'
	UTILITY PLANT AND JOINTLY-OWNED FACILITIES
	UTILITY PLANT
	The following table shows Utility Plant in Service by major class:
		UNS Energy								TEP
		December 31,								December 31,
		2013				2012				2013				2012
		Millions of Dollars
	Plant in Service:
	Electric Generation Plant	$	1,974			$	1,932			$	1,889			$	1,847
	Electric Transmission Plant	912				842				825				796
	Electric Distribution Plant	1,529				1,495				1,298				1,271
	Gas Distribution Plant	252				240				—				—
	Gas Transmission Plant	18				18				—				—
	General Plant	356				347				312				309
	Intangible Plant - Software Costs (1) (2)	142				124				141				123
	Intangible Plant - Other	5				5				—				—
	Electric Plant Held for Future Use	4				3				3				2
	Total Plant in Service	$	5,192			$	5,006			$	4,468			$	4,348
	Utility Plant under Capital Leases(3)	$	638			$	583			$	638			$	583
	(1)	Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.
	(2)	The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.
	(3)	In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.
	TEP Utility Plant under Capital Leases
	All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term. See Note 6. At December 31, 2013, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:
		Years Ended December 31,
		2013				2012				2011
		Millions of Dollars
	Lease Expense:
	Interest Expense – Included in:
	Capital Leases	25				$	34			$	40
	Operating Expenses – Fuel	2				3				4
	Other Expense	—				—				1
	Amortization of Capital Lease Assets – Included in:
	Operating Expenses – Fuel	5				4				3
	Operating Expenses – Amortization	15				14				14
	Total Lease Expense	$	47			$	55			$	62
	Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2013, were as follows:
		TEP
		31-Dec-13
		Annual Depreciation Rate (5)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Electric Generation Plant (1)	3.31%		22
	Electric Transmission Plant	1.48%		32
	Electric Distribution Plant (1)	2.08%		35
	General Plant (1)	5.48%		11
	Intangible Plant (2)	Various		Various
		UNS Electric
		31-Dec-13
		Annual Depreciation Rate (5)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Electric Generation Plant	2.56%		36
	Electric Transmission Plant	3.36%		19
	Electric Distribution Plant	3.97%		15
	General Plant	8.01%		7
	Intangible Plant (3)	Various		Various
		UNS Gas
		31-Dec-13
		Annual Depreciation Rate (5)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Gas Generation Plant	2.37%		41
	Gas Transmission Plant	1.54%		54
	General Plant	4.38%		7
	Intangible Plant (4)	Various		Various
-1	In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.
(2)	The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life based on either the average lives of 3 to 5 years for smaller application software or remaining lives ranging from 5 to 19 years for large enterprise software.
(3)	UNS Electric's intangible plant primarily represents capitalized interconnection costs, which are amortized based on either an average life of 23 years or a remaining life of 35 years.
(4)	UNS Gas' intangible plant consists of miscellaneous intangible assets, which are amortized over an average life of either 15 or 25 years.
(5)	The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.
JOINTLY-OWNED FACILITIES
At December 31, 2013, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:
	Ownership Percentage		Plant in Service				Construction Work in				Accumulated Depreciation				Net Book Value
							Progress
			Millions of Dollars
San Juan Units 1 and 2	50.00%		$	448			$	6			$	230			$	224
Navajo Units 1, 2, and 3	7.50%		152				1				110				43
Four Corners Units 4 and 5	7.00%		101				2				75				28
Luna Energy Facility	33.30%		53				—				2				51
Transmission Facilities	Various		330				43				190				183
Total			$	1,084			$	52			$	607			$	529
TEP is responsible for its share of operating costs for the above facilities as well as providing financing. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
ASSET RETIREMENT OBLIGATIONS
The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:
	UNS Energy
	December 31,
	2013				2012
	Millions of Dollars
Beginning Balance	$	14			$	13
Liabilities Incurred	1				—
Accretion Expense or Regulatory Deferral	1				1
Revisions to the Present Value of Estimated Cash Flows (1)	7				—
Ending Balance	$	23			$	14
-1	Primarily related to changes in expected retirement dates of generating facilities.
The table above primarily reflects TEP's ARO obligations. UNS Electric's ARO obligations were less than $1 million at December 31, 2013 and 2012.

DEBT_CREDIT_FACILITIES_AND_CAP

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	'
	DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS
	Long-term debt matures more than one year from the date of the financial statements. We summarize UNS Energy’s and TEP’s long-term debt in the statements of capitalization.
	UNS ENERGY CONVERTIBLE SENIOR NOTES
	In 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. In 2012, UNS Energy converted approximately $147 million of the Convertible Senior Notes into approximately 4.3 million shares of Common Stock and redeemed $3 million for cash.
	TEP DEBT ISSUANCES AND REDEMPTIONS
	Unsecured Tax-Exempt Variable Rate Bonds
	In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate Industrial Development Revenue Bonds (IDRBs), due April 2032. The lender resets the interest rate monthly based on a percentage of an index rate equal to one-month LIBOR plus a bank margin rate; the rate at December 31, 2013 was 0.948% per annum. These bonds are multi-modal bonds, and the initial term is set at five years through November 2018, at which time the bonds will be subject to mandatory tender for purchase. Proceeds were deposited with a trustee to redeem $100 million variable rate bonds in December 2013.
	Secured Tax-Exempt Variable Rate Bonds and Interest Rate Swap
	Certain of TEP's tax-exempt, variable rate bonds are secured by Letter of Credits (LOCs) issued under the TEP Credit Agreement and TEP Reimbursement Agreement, see below.
	The following table shows interest rates on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents:
		Years Ended December 31,
		2013		2012		2011
	Interest Rates on Bonds:
	Average Interest Rate	0.10%		0.17%		0.18%
	Range of Average Weekly Rates	0.06% - 0.25%		0.06% - 0.26%		0.05% - 0.34%
	In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014.
	Unsecured Tax-Exempt Fixed Rate Bonds
	In March 2013, TEP issued approximately $91 million aggregate principal amount of Pima County, Arizona, unsecured tax-exempt Industrial Development Bonds (IDBs). 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 were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013.
	In June 2012, TEP issued approximately $16 million of Pima County, Arizona, unsecured tax-exempt IDBs. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $16 million of unsecured, tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033.
	In March 2012, TEP issued $177 million of Apache County, Arizona, unsecured, tax-exempt pollution control bonds. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875% and maturity dates ranging from 2026 to 2033.
	Unsecured Fixed Rate Notes
	In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the revolving credit facility, with the remaining proceeds used for general corporate purposes.
	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 canceled $423 million in mortgage bonds and discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.
	UNS ENERGY CREDIT AGREEMENT
	The UNS Energy Credit Agreement consists of a $125 million revolving credit facility and revolving LOC facility and expires in November 2016. UNS Energy’s obligations under the agreement are secured by a pledge of the capital stock of Millennium, UES, and UED.
	UNS Energy had $54 million of outstanding borrowings at December 31, 2013 and $45 million of outstanding borrowings at December 31, 2012, under its revolving credit facility. The weighted average interest rate on the revolver was 1.66% at December 31, 2013 and 1.96% at December 31, 2012. We report the revolver borrowings in Long-Term Debt on the balance sheet as UNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 14, 2014, outstanding borrowings under the UNS Energy Credit Agreement totaled $52 million.
	Interest rates and fees under the UNS Energy Credit Agreement are based on a pricing grid tied to UNS Energy’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.25% for Eurodollar loans or Alternate Base Rate plus 0.25% for Alternate Base Rate loans.
	TEP CREDIT AGREEMENT
	The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility, and a $82 million LOC facility to support tax-exempt bonds, and expires in November 2016. In December 2013, TEP reduced its letter of credit facility from $186 million to $82 million, following the refinancing of $100 million of variable rate bonds and the cancellation of $104 million of LOCs supporting those bonds.
	Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million LOC facility is 1.125%.
	TEP had no borrowings and $1 million outstanding in LOCs issued under its revolving credit facility at December 31, 2013 and December 31, 2012. The revolving loan balance was included in Current Liabilities on UNS Energy’s and TEP’s balance sheets. The outstanding LOCs are off-balance sheet obligations of TEP. As of February 14, 2014, TEP had $90 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility.
	2010 TEP REIMBURSEMENT AGREEMENT
	A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010. In February 2014, TEP amended the agreement to extend the LOC expiration date from 2014 to 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 1.00% per annum.
	UNS ELECTRIC/UNS GAS CREDIT AGREEMENT
	The UNS Electric/UNS Gas Credit Agreement consists of a $100 million revolving credit and revolving LOC facility, and expires in November 2016. The maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. UNS Electric and UNS Gas each are liable for only their own individual borrowings under the UNS Electric/UNS Gas Credit Agreement. UES guarantees the obligations of both UNS Electric and UNS Gas. The UNS Electric/UNS Gas Credit Agreement may be used to issue LOCs, as well as for revolver borrowings. UNS Electric and UNS Gas issue LOCs, which are off-balance sheet obligations, to support power and gas purchases and hedges.
	Interest rates and fees under the UNS Electric/UNS Gas Credit Agreement are based on a pricing grid tied to their credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans.
	UNS Electric had $22 million in borrowings and less than $0.5 million in outstanding LOCs under the UNS Electric/UNS Gas Credit Agreement as of December 31, 2013. The revolving loan balance was included in Current Liabilities on UNS Energy’s balance sheet. UNS Electric had no borrowings outstanding and less than $0.5 million LOCs under UNS Electric/UNS Gas Credit Agreement as of December 31, 2012. The oustanding LOCs balances are not shown on the balance sheet. As of February 14, 2014, UNS Electric had $25 million in borrowings and less than $0.5 million in outstanding LOCs under the UNS Electric/UNS Gas Credit Agreement.
	UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP
	In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four years period ending August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES.
	COVENANT COMPLIANCE
	Our credit agreements, the 2010 TEP Reimbursement Agreement, and certain of our long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. The UNS Energy Credit Agreement also requires UNS Energy to meet a minimum cash flow to interest coverage ratio, and each of our credit agreements stipulate a maximum leverage ratio. UNS Energy and its subsidiaries may pay dividends so long as we maintain compliance with our credit agreements.
	At December 31, 2013, we were in compliance with the terms of our long-term debt, credit agreements, and the 2010 TEP Reimbursement Agreement. No amounts of net income were subject to dividend restrictions.
	TEP CAPITAL LEASE OBLIGATIONS
	In January 2014, through scheduled lease payments, TEP reduced its capital lease obligations by $80 million.
	Springerville Unit 1 Capital Lease Purchase Commitments
	The Springerville Unit 1 Leases have an initial term to January 2015, and include a fair market value purchase option at the end of the initial lease term. 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 capacity rating of 387 MW.
	In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value, 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 capacity, 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 capacity. Due to TEP's purchase commitments, TEP and UNS Energy recorded an increase of approximately $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets.
	Springerville Coal Handling and Common Facilities Leases
	The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for fixed-rate lease renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million. The leases provide for one renewal period of six years beginning in April 2015, with additional renewal periods of five or more years through 2035.
	The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. Instead of extending the leases, TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of the common facilities are $38 million in 2017 and $68 million in 2021.
	TEP agreed with Tri-State, the owner of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Facilities Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either: buy a portion of these facilities; or continue making payments to TEP for the use of these facilities.
	Lease Debt and Equity
	Investments in Springerville Lease Debt and Equity
	In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2013 and December 31, 2012.
	Interest Rate Swaps—Springerville Common Facilities Lease Debt
	TEP’s interest rate swaps hedge the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month London Interbank Offered Rate (LIBOR) plus a spread. The applicable spread was 1.75% at December 31, 2013 and December 31, 2012.
	The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:
	Lease Debt Outstanding at December 31, 2013	Fixed			LIBOR
		Rate			Spread
	Swap 1 - Notional Amount $33 million - Effective Date June 2006	5.77	%		1.75	%
Swap 2 - Notional Amount $16 million - Effective Date May 2009	3.18	%		1.75	%
Swap 3 - Notional Amount $6 million - Effective Date May 2009	3.32	%		1.75	%
TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 15.
DEBT MATURITIES
Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
	TEP				TEP			TEP			UNS		UNS		UNS		Total
	Long-Term				Capital			Total			Electric		Gas		Energy
	Debt				Lease										Parent
	Maturities (1)				Obligations										Company
	Millions of Dollars
2014	$	—			$	214		$	214		$	—	$	—	$	—	$	214
2015	—				69			69			80		50		—		199
2016	78				17			95			—		—		54		149
2017	—				18			18			—		—		—		18
2018	100				11			111			—		—		—		111
Total 2014 – 2018	178				329			507			80		50		54		691
Thereafter	1,046				30			1,076			50		50		—		1,176
Less: Imputed Interest	—				(42		)	(42		)	—		—		—		(42		)
Total	$	1,224			$	317		$	1,541		$	130	$	100	$	54	$	1,825
(1)	$115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS	'
	COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
	COMMITMENTS
	At December 31, 2013, UNS Energy and TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases. UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas:
		UNS Energy Purchase Commitments
		2014		2015			2016			2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	103	$	83		$	80		$	75	$	49	$	345	$	735
	Purchased Power	75		17			—			—		—		—		92
	Transmission	7		13			12			12		11		27		82
	Renewable Power Purchase Agreements	36		37			37			37		37		485		669
	RES Performance-Based Incentives	9		9			9			9		9		85		130
	Operating Leases	4		4			3			2		2		14		29
	Total Purchase Commitments	$	234	$	163		$	141		$	135	$	108	$	956	$	1,737
	At December 31, 2013, TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases:
		TEP Purchase Commitments
		2014		2015			2016			2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	77	$	63		$	64		$	62	$	36	$	285	$	587
	Purchased Power	27		5			—			—		—		—		32
	Transmission	3		6			6			6		6		21		48
	Renewable Power Purchase Agreements	30		31			31			31		31		410		564
	RES Performance-Based Incentives	8		8			8			8		8		83		123
	Operating Leases	3		3			2			2		2		14		26
	Total Purchase Commitments	$	148	$	116		$	111		$	109	$	83	$	813	$	1,380
	Fuel
	TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more than the minimum purchase obligations to meet its fuel requirements. TEP's fuel costs are recoverable from customers through the PPFAC.
	UNS Gas purchases gas from various supplies at market prices. However, UNS Gas' risk of loss due to increased costs is mitigated through the use of the PGA, which provides for the pass-through of actual commodity costs to customers. UNS Gas' forward gas purchase agreements expire through 2016. Certain of these contracts are at a fixed price per Million British Thermal Units (MMbtu) and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected marked prices as of December 31, 2013. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2016 and 2023.
	Purchased Power and Transmission
	TEP and UNS Electric have agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in 2014 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2013.
	TEP has agreements with other utilities to provide transmission services. These contracts expire in various years between 2018 and 2028. UNS Electric imports the power it purchases over the Western Area Power Administration's (WAPA) transmission lines. UNS Electric's transmission capacity agreements with WAPA provide for annual rate adjustments and expire in 2016.
	TEP's and UNS Electric's purchased power and transmission costs are recoverable from customers through their respective PPFAC mechanisms.
	Renewable Power Purchase Agreements and RES Performance-Based Incentives
	TEP and UNS Electric have entered into 20 year Renewable Power Purchase Agreements (PPAs) which require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. TEP has entered into additional long-term renewable PPAs to comply with RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 3.
	TEP and UNS Electric have entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 3.
	Operating Leases
	Our operating lease expense is primarily for rail cars, office facilities, land easements, and rights of way with varying terms, provisions, and expiration dates. UNS Energy's operating lease expense totaled $3 million in each of 2013, 2012, and 2011, and TEP's operating lease expense totaled $2 million in each of 2013, 2012, and 2011.
	TEP CONTINGENCIES
	Potential Purchase of Gas-Fired Generation Facility
	In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility; see Note 8.
	Claim Related to San Juan Generating Station
	San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
	In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.
	Claims Related to Four Corners Generating Station
	In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The joint participants have applied to have the matter stayed until March 17, 2014 in furtherance of settlement talks.
	TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.
	In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. 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 at all three mines is expected to be $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $18 million at December 31, 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 and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
	Discontinued Transmission Project
	TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the 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 3. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery.
	Performance Guarantees
	The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. TEP's joint participation agreements expire in 2016 through 2046.
	UNS ELECTRIC CONTINGENCIES
	Potential Purchase of Gas-Fired Generation Facility
	In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 8.
	ENVIRONMENTAL MATTERS
	Environmental Regulation
	The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $5 million in 2013, $2 million in 2012, and $8 million in 2011 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $12 million in 2014 and $36 million in 2015. In addition, TEP recorded O&M expenses of $8 million in 2013, $15 million in 2012, and $12 million in 2011. TEP expects environmental O&M expenses to be $5 million in each of 2014 and 2015.
	TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
	Hazardous Air Pollutant Requirements
	In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATs) rule, additional emission control equipment will be required by 2015. The estimated costs include:
Estimated Emissions Control Costs:	Navajo		Four Corners			Springerville
	Millions of Dollars
Capital Expenditures - Mercury Emissions Control	$	1	$	1		$	5
Annual O&M Expenses	1		1			3
TEP expects Sundt and San Juan's current emission controls to be adequate to comply with the EPA's final standards.
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 in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install SCRs. Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.
TEP's estimated potential costs involved in meeting these rules are:
Estimated Potential Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)			Sundt (4)
	Millions of Dollars
Capital - SCR	$	42	$ 180-200		$	35		$	—
Capital - SNCR	—		35		—			12
Annual O&M - SCR	1		6		2			—
Annual O&M - SNCR	—		1		—			6-May
-1	The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.
-2	The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 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.
-3	On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.
(4) In January 2014, the EPA issued a proposal that would require TEP to either (i) install SNCR by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is expected to issue a final BART determination by July 2014. At December 31, 2013, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.
BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the plant was built after the BART-applicable dates.

POTENTIAL_PURCHASE_OF_GASFIRED

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY	12 Months Ended
	Dec. 31, 2013
Potential Purchase of Gas-Fired Generation Facility [Abstract]	'
POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY	'
	POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY
	On December 23, 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Generating Station Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to regulatory approvals and other closing conditions. In December 2013, UNS Electric filed an application for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3.
	TEP expects to provide a letter of credit in March 2014 for $15 million to satisfy a condition of the purchase agreement. The seller of Gila River Unit 3 would be entitled to draw upon the letter of credit and apply such amount as liquidated damages if it has validly terminated the Purchase Agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the letter of credit would be canceled.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 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
		Years Ended December 31,
		2013			2012				2011			2013			2012			2011
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	65		$	51			$	62		$	52		$	37		$	48
	State Income Tax Expense, Net of Federal Deduction	8			7				8			7			5			6
	Federal/State Tax Credits	(2		)	(1		)		(3		)	(2		)	(1		)	(2		)
	Allowance for Equity Funds Used During Construction	(2		)	(1		)		(1		)	(1		)	(1		)	(1		)
	Deferred Tax Asset Valuation Allowance	—			—				—			2			—			—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—				—			(11		)	—			—
	Other	—			—				1			1			(1		)	1
	Total Federal and State Income Tax Expense	$	58		$	56			$	67		$	48		$	39		$	52
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset
	Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.
	Income tax expense included in the income statements consists of the following:
		UNS Energy										TEP
		Years Ended December 31,
		2013			2012				2011			2013			2012			2011
		Millions of Dollars
	Current Tax Expense (Benefit):
	Federal	$	(11	)	$	(2	)		$	(7	)	$	(8	)	$	(4	)	$	(5	)
	State	(2		)	(2		)		(2		)	(2		)	(2		)	(2		)
	Total Current Tax Expense (Benefit)	(13		)	(4		)		(9		)	(10		)	(6		)	(7		)
	Deferred Tax Expense (Benefit):
	Federal	61			51				64			47			38			50
	Federal Investment Tax Credits	(1		)	—				(1		)	(1		)	—			(1		)
	State	11			9				13			12			7			10
	Total Deferred Tax Expense (Benefit)	71			60				76			58			45			59
	Total Federal and State Income Tax Expense	$	58		$	56			$	67		$	48		$	39		$	52
	The significant components of deferred income tax assets and liabilities consist of the following:
		UNS Energy							TEP
		December 31,							December 31,
		2013			2012				2013			2012
		Millions of Dollars
	Gross Deferred Income Tax Assets:
	Capital Lease Obligations	$	127		$	141			$	127		$	141
	Net Operating Loss Carryforwards	94			72				104			85
	Customer Advances and Contributions in Aid of Construction	33			34				19			19
	Alternative Minimum Tax Credit	43			43				24			24
	Accrued Postretirement Benefits	23			23				23			23
	Renewable Energy Credit Up-Front Incentive Payments	—			26				—			20
	Emission Allowance Inventory	10			10				10			10
	Unregulated Investment Losses	7			9				—			—
	Other	50			44				44			43
	Total Gross Deferred Income Tax Assets	387			402				351			365
	Deferred Tax Assets Valuation Allowance	(7		)	(7		)		(2		)	—
	Gross Deferred Income Tax Liabilities:
	Plant – Net	(708		)	(648		)		(615		)	(571		)
	Capital Lease Assets – Net	(47		)	(34		)		(47		)	(34		)
	Pensions	(21		)	(23		)		(22		)	(24		)
	PPFAC	(5		)	(6		)		(2		)	(3		)
	Other	(21		)	(15		)		(20		)	(15		)
	Total Gross Deferred Income Tax Liabilities	(802		)	(726		)		(706		)	(647		)
	Net Deferred Income Tax Liabilities	$	(422	)	$	(331	)		$	(357	)	$	(282	)
	The net deferred income tax liability on the balance sheet is as follows:
		UNS Energy							TEP
		December 31,							December 31,
		2013			2012				2013			2012
		Millions of Dollars
	Deferred Income Taxes – Current Assets	$	60		$	34			$	64		$	37
	Deferred Income Taxes – Noncurrent Liabilities	(482		)	(365		)		(421		)	(319		)
Net Deferred Income Tax Liability	$	(422	)	$	(331	)		$	(357	)	$	(282	)
The unregulated investment loss deferred tax asset includes $7 million of capital loss at December 31, 2013 and December 31, 2012. The deferred tax asset can only be used if the company has capital gains to offset the losses. Management believes that it is more likely than not that the company will not be able to generate future capital gains. As a result, UNS Energy recorded a $7 million valuation allowance against the deferred tax asset as of December 31, 2013, and December 31, 2012. Management believes that based on its historical pattern of taxable income, UNS Energy will produce sufficient income in the future to realize all other deferred income tax assets. TEP has recorded a $2 million valuation allowance against state tax credit carryforward deferred tax assets at December 31, 2013. Management believes TEP will not produce sufficient taxable income to use all state tax credits before they expire.
Income Tax Position
As of December 31, 2013, UNS Energy and TEP had the following carryforward amounts:
	UNS Energy					TEP
	Amount			Expiring Year		Amount				Expiring Year
	Millions of Dollars					Millions of Dollars
Capital Loss	$	7		2015		$	—			N/A
Federal Net Operating Loss	266			2031-33		286				2031-33
State Net Operating Loss	30			2032-33		99				2016-33
State Credits	5			2016-18		6				2016-18
Alternative Minimum Tax Credit	43			None		24				None
Investment Tax Credits	6			2032-33		6				2032-33
If the pending Merger is approved there would be an annual limitation on the amount of carryforwards that can be utilized.
Excess Tax Benefit Realized from Share-Based Compensation Plans
UNS Energy records excess tax benefits as an increase to Common Stock when tax deductions for share-based compensation exceed the expense recorded in the financial statements and they result in a reduction to income taxes payable. As of December 31, 2013, UNS Energy had $4 million of excess tax benefits that were not recorded in Common Stock. The excess benefits will be recorded in Common Stock when the Federal net operating loss carryforwards of $266 million are used.
Uncertain Tax Positions
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
	UNS Energy							TEP
	December 31,							December 31,
	2013			2012				2013			2012
	Millions of Dollars
Unrecognized Tax Benefits, Beginning of Year	$	30		$	29			$	23		$	24
Additions Based on Tax Positions Taken in the Current Year	2			5				1			3
Reductions of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(4		)		(22		)	(4		)
Unrecognized Tax Benefits, End of Year	$	4		$	30			$	2		$	23
Unrecognized tax benefits, if recognized, would not reduce income tax expense at December 31, 2013. Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million at December 31, 2012 for both UNS Energy and TEP.
UNS Energy and TEP recognized a $1 million reduction to interest expense in 2013 and no reduction in 2012. UNS Energy and TEP had no interest payable balance at December 31, 2013 and $1 million at December 31, 2012. We have no penalties accrued in the years presented.
In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources.  These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation.  As a result of the IRS ruling in the first quarter of 2013, 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.
UNS Energy and TEP have been audited by the IRS through tax year 2010 and the IRS has provided notice of intent to audit the 2011 tax returns. UNS Energy and TEP are not currently under audit by any state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of ongoing IRS audits, but we are unable to determine the amount of change.
Tangible Property Regulations
In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. The adoption of these regulations by UNS Energy and TEP resulted in a $4 million increase to plant-related deferred tax liabilities and net operating loss deferred tax assets at December 31, 2013.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
EMPLOYEE BENEFIT PLANS	'
	EMPLOYEE BENEFIT PLANS
	PENSION BENEFIT PLANS
	We sponsor three noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.
	We also maintain a Supplemental Executive Retirement Plan (SERP) for executive management.
	OTHER RETIREE BENEFIT PLANS
	TEP provides limited health care and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. UNS Electric and UNS Gas provide retiree medical benefits for current retirees. UNS Electric's and UNS Gas' active employees are not eligible for retiree medical benefits.
	TEP funds its other retiree benefits for classified employees through a Voluntary Employee Beneficiary Association (VEBA). TEP contributed $3 million in each of 2013 and 2012 and $2 million in 2011 to the VEBA. Other retiree benefits for unclassified employees are self funded.
	TEP’s other retiree benefit plan was amended in 2012 to increase the participant contributions for classified employees who retire after February 1, 2014. The effect on the benefit obligation was less than $1 million.
	REGULATORY RECOVERY
	We record changes in our non-SERP pension plans and other retiree benefit plan, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income since SERP expense is not currently recoverable in rates.
	The pension and other retiree benefit related amounts (excluding tax balances) included on the UNS Energy balance sheet are:
		Pension Benefits								Other  Retiree
										Benefits
		Years Ended December 31,
		2013				2012				2013			2012
		Millions of Dollars
	Regulatory Pension Asset Included in Other Regulatory Assets	$	75			$	129			$	4		$	10
	Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)		(1		)		(2		)	(2		)
	Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(28		)		(90		)		(63		)	(69		)
	Accumulated Other Comprehensive Loss (related to SERP)	2				4				—			—
	Net Amount Recognized	$	48			$	42			$	(61	)	$	(61	)
	The table above includes accrued pension benefit liabilities for UNS Electric and UNS Gas of approximately $5 million at December 31, 2013 and $9 million at December 31, 2012. The table also includes an other retiree benefit liability of $1 million for UNS Electric and UNS Gas for each period presented.
	OBLIGATIONS AND FUNDED STATUS
	We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2013 and December 31, 2012. The table below includes TEP’s, UNS Electric’s, and UNS Gas’ plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below:
		Pension Benefits								Other  Retiree
										Benefits
		Years Ended December 31,
		2013				2012				2013			2012
		Millions of Dollars
	Change in Projected Benefit Obligation
	Benefit Obligation at Beginning of Year	$	380			$	319			$	78		$	73
	Actuarial (Gain) Loss	(38		)		51				(5		)	3
	Interest Cost	15				15				3			3
	Service Cost	13				10				3			3
	Benefits Paid	(18		)		(15		)		(4		)	(4		)
	Projected Benefit Obligation at End of Year	352				380				75			78
	Change in Plan Assets
	Fair Value of Plan Assets at Beginning of Year	289				245				7			5
	Actual Return on Plan Assets	29				36				1			1
	Benefits Paid	(18		)		(15		)		(4		)	(4		)
	Employer Contributions (1)	23				23				6			5
	Fair Value of Plan Assets at End of Year	323				289				10			7
	Funded Status at End of Year	$	(29	)		$	(91	)		$	(65	)	$	(71	)
	(1)	TEP made $22 million in pension contributions and $6 million in other retiree benefits contributions in 2013 and $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012. In 2014, UNS Energy expects to contribute $10 million to the pension plans, including $9 million in contributions by TEP.
	The table above includes the following for UNS Electric and UNS Gas:
	•	Pension benefit obligations of $21 million at December 31, 2013 and $23 million at December 31, 2012;
	•	Plan assets of $16 million at December 31, 2013 and $14 million at December 31, 2012; and
	•	A retiree benefit obligation of $1 million at December 31, 2013 and December 31, 2012.
	The following table provides the components of UNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:
		Pension Benefits								Other  Retiree
										Benefits
		Years Ended December 31,
		2013				2012				2013			2012
		Millions of Dollars
	Net Loss	$	77			$	133			$	7		$	13
	Prior Service Cost (Benefit)	—				1				(3		)	(3		)
	The accumulated benefit obligation aggregated for all pension plans is $314 million at December 31, 2013 and $334 million at December 31, 2012.
	Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
		December 31,
		2013			2012
		Millions of Dollars
	Accumulated Benefit Obligation at End of Year	30			334
	Fair Value of Plan Assets at End of Year	16			289
At December 31, 2012, all four UNS Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets. Due to 2013 contributions, returns on plan assets, and the favorable impact of the increase in the discount rate on the accumulated benefit obligations, only the SERP, which is unfunded, and the UES plan have accumulated benefit obligations in excess of plan assets at December 31, 2013.
UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:
	Pension Benefits											Other Retiree Benefits
	Years Ended December 31,
	2013				2012				2011			2013			2012			2011
	Millions of Dollars
Service Cost	$	13			$	10			$	10		$	4		$	3		$	3
Interest Cost	15				16				15			3			3			4
Expected Return on Plan Assets	(20		)		(17		)		(16		)	(1		)	—			—
Prior Service Cost Amortization	—				—				—			(1		)	—			(1		)
Actuarial Loss Amortization	9				7				6			1			—			—
Net Periodic Benefit Cost	$	17			$	16			$	15		$	6		$	6		$	6
Approximately 21% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:
	Pension Benefits
	2013								2012						2011
	Regulatory				AOCI				Regulatory			AOCI			Regulatory			AOCI
	Asset								Asset						Asset
	Millions of Dollars
Current Year Actuarial (Gain) Loss	$	(46	)		$	(1	)		$	30		$	1		$	25		$	(2	)
Amortization of Actuarial Gain (Loss)	(8		)		—				(7		)	—			(5		)	—
Total Recognized (Gain) Loss	$	(54	)		$	(1	)		$	23		$	1		$	20		$	(2	)
	Other Retiree Benefits
	2013				2012				2011
	Regulatory				Regulatory				Regulatory
	Asset				Asset				Asset
	Millions of Dollars
Prior Service Cost (Credit)	$	—			$	—			$	(2	)
Current Year Actuarial (Gain) Loss	(6		)		2				—
Amortization of Actuarial (Gain) Loss	(1		)		—				—
Amortization of Prior Service (Cost) Credit	1				—				1
Total Recognized (Gain) Loss	$	(6	)		$	2			$	(1	)
For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $4 million estimated net loss and less than $1 million prior service cost from other regulatory assets and less than $1 million prior service cost from AOCI into net periodic benefit cost in 2014. The estimated prior service benefit for the other retiree benefit plan that will be amortized from other regulatory assets into net periodic benefit cost in 2014 is less than $1.0 million.
	Pension Benefits				Other Retiree
					Benefits
	2013		2012		2013		2012
Weighted-Average Assumptions Used to Determine
Benefit Obligations as of December 31,
Discount Rate	5.0% - 5.2%		4.1%-4.3%		4.70%		3.80%
Rate of Compensation Increase	3.00%		3.00%		N/A		N/A
	Pension Benefits						Other Retiree Benefits
	2013		2012		2011		2013		2012		2011
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate	4.1%-4.3%		4.9% - 5.0%		5.5% - 5.6%		3.80%		4.70%		5.20%
Rate of Compensation Increase	3.00%		3.00%		3.0% - 5.0%		N/A		N/A		N/A
Expected Return on Plan Assets	7.00%		7.00%		7.00%		7.00%		7.00%		5.10%
Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets.
We use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward looking return expectations only. The above method is used for all asset classes.
Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. The assumed health care cost trend rates follow:
	December 31,
	2013		2012
Health Care Cost Trend Rate Assumed for Next Year	6.70%		6.90%
Ultimate Health Care Cost Trend Rate Assumed	4.50%		4.50%
Year that the Rate Reaches the Ultimate Trend Rate	2027		2027
Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2013, amounts:
	One-Percentage-				One-Percentage-
	Point Increase				Point Decrease
	Millions of Dollars
Effect on Total Service and Interest Cost Components	$	1			$	(1	)
Effect on Retiree Benefit Obligation	6				(5		)
PENSION PLAN AND OTHER RETIREE BENEFIT ASSETS
Pension Assets
We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows:
	TEP Plan Assets						UNS Electric and UNS Gas Plan
							Assets
	2013			2012			2013			2012
Asset Category
Equity Securities	50	%		50	%		50	%		56	%
Fixed Income Securities	40			41	%		40			33
Real Estate	7			7	%		10			11
Other	3			2	%		—			—
Total	100	%		100	%		100	%		100	%
The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:
	Fair Value Measurements of Pension Assets
	December 31, 2013
	Quoted Prices				Significant Other				Significant			Total
	in Active				Observable				Unobservable
	Markets				Inputs				Inputs
	(Level 1)				(Level 2)				(Level 3)
	Millions of Dollars
Asset Category
Cash Equivalents	$	1			$	—			$	—		$	1
Equity Securities:
United States Large Cap	—				80				—			80
United States Small Cap	—				17				—			17
Non-United States	—				65				—			65
Fixed Income	—				130				—			130
Real Estate	—				9				14			23
Private Equity	—				—				7			7
Total	$	1			$	301			$	21		$	323
	Fair Value Measurements of Pension Assets
	December 31, 2012
	Level 1				Level 2				Level 3			Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1			$	—			$	—		$	1
Equity Securities:
United States Large Cap	—				71				—			71
United States Small Cap	—				15				—			15
Non-United States	—				59				—			59
Fixed Income	—				116				—			116
Real Estate	—				8				13			21
Private Equity	—				—				6			6
Total	$	1			$	269			$	19		$	289
Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 85% of real estate assets tracked by the index in 2013 and comprising 87% in 2012.
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UNS Electric and UNS Gas pension plan of $16 million at December 31, 2013 and $14 million at December 31, 2012.
The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
	Year Ended
	December 31, 2013
	Private				Real Estate				Total
	Equity
	Millions of Dollars
Beginning Balance at January 1, 2013	$	6			$	13			$	19
Actual Return on Plan Assets:
Assets Held at Reporting Date	1				1				2
Purchases, Sales, and Settlements	—				—				—
Ending Balance at December 31, 2013	$	7			$	14			$	21
	Year Ended
	December 31, 2012
	Private				Real Estate				Total
	Equity
	Millions of Dollars
Beginning Balance at January 1, 2012	$	4			$	11			$	15
Actual Return on Plan Assets:
Assets Held at Reporting Date	1				2				3
Purchases, Sales, and Settlements	1				—				1
Ending Balance at December 31, 2012	$	6			$	13			$	19
UNS Electric and UNS Gas have no pension assets classified as Level 3 in the fair value hierarchy.
Pension Plan Investments
Investment Goals
Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. We consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.
Risk Management
We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: plan status, plan sponsor financial status and profitability, plan features, and workforce characteristics. We have determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
Relationship between Plan Assets and Benefit Obligations
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation.
Target Allocation Percentages
The current target allocation percentages for the major asset categories of the plan as of December 31, 2013 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.
	TEP Plan		UNS Electric and UNS Gas Plan		VEBA Trust
Fixed Income	41%		42%		38%
United States Large Cap	24%		24%		39%
Non-United States Developed	15%		14%		7%
Real Estate	8%		10%		—%
United States Small Cap	5%		5%		5%
Non-United States Emerging	5%		5%		9%
Private Equity	2%		—%		—%
Cash/Treasury Bills	—%		—%		2%
Total	100%		100%		100%
Pension Fund Descriptions
For each type of asset category selected by the Pension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds.
Other Retiree Benefit Assets
As of December 31, 2013, the fair value of VEBA trust assets was $10 million, of which $4 million were fixed income investments and $6 million were equities. As of December 31, 2012, the fair value of VEBA trust assets was $7 million, of which $3 million were fixed income investments and $4 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust.
ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate.
	2014				2015				2016			2017			2018			2019-2023
	Millions of Dollars
Pension Benefits	$	15			$	16			$	17		$	18		$	20		$	114
Other Retiree Benefits	5				5				5			5			5			29
One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million.
UNS Electric and UNS Gas expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $7 million in 2014 through 2018, and $9 million in 2019 through 2023.
DEFINED CONTRIBUTION PLAN
We offer a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account which may include a UNS Energy stock fund. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in each of 2013, 2012, and 2011. UNS Electric and UNS Gas made matching contributions of less than $1 million in each of 2013, 2012, and 2011.

SHAREBASED_COMPENSATION_PLANS

SHARE-BASED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
SHARE-BASED COMPENSATION PLANS	'
	SHARE-BASED COMPENSATION PLANS
	Under the UNS Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), the Compensation Committee of the UNS Energy Board of Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted stock units, and performance shares. The total number of shares which may be awarded under the 2011 Plan cannot exceed 1.2 million shares.
	STOCK OPTIONS
	Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant, and expire on the tenth anniversary of the grant. We recognize compensation expense on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement-eligible officers, we recognize compensation expense immediately. No stock options were granted by the Compensation Committee in 2013, 2012, or 2011.
	See summary of stock option activity in the table below:
			2013						2012							2011
	Stock Options		Shares		Weighted				Shares			Weighted				Shares			Weighted
			(000s)		Average				(000s)			Average				(000s)			Average
					Exercise							Exercise							Exercise
					Price							Price							Price
	Outstanding, Beginning of Year		409		$	29.09			581			$	29.11			921			$	27.96
	Exercised		(127	)	30.12				(132	)		26.54				(319	)		25.6
	Forfeited/Expired		—		—				(40	)		37.88				(21	)		31.92
	Outstanding, End of Year		282		28.63				409			29.09				581			29.11
	Exercisable, End of Year		282		$	28.63			409			$	29.09			508			$	29.53
	Aggregate Intrinsic Value of Options Exercised ($000s)				$	2,897						$	1,878						$	3,690
	See summary of stock options in the tables below:
		31-Dec-13
	Aggregate Intrinsic Value for Options Outstanding ($000s)	$	8,795
	Aggregate Intrinsic Value for Options Exercisable ($000s)	$	8,795
	Weighted Average Remaining Contractual Term of Outstanding Options	4.1 years
	Weighted Average Remaining Contractual Term of Exercisable Options	4.1 years
			Options Outstanding								Options Exercisable
	Range of Exercise Prices		Number  of		Weighted		Weighted				Number  of			Weighted
			Shares		Average		Average				Shares			Average
			(000s)		Remaining		Exercise				(000s)			Exercise Price
					Contractual		Price
					Term
	$26.11—$37.88		282		4.1 years		$	28.63			282			$	28.63
	RESTRICTED STOCK UNITS AND PERFORMANCE SHARES
	Restricted Stock Units
	In 2013, 2012, and 2011, the Compensation Committee granted restricted stock units to non-employee directors. We recognize compensation expense equal to the fair valuin the tablee 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 Common Stock for the vested stock units in the January following the year the person is no longer a director.
	In 2013, the Compensation Committee granted restricted stock units to certain management employees. 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. The grant date fair value was the closing Common Stock market price on the date of grant. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.
	See summary of restricted stock units awarded in the table below:
			Non-Employee Directors						Management Employees
	Award Year		Restricted Stock Units		Grant Date Fair Value				Restricted Stock Units			Grant Date Fair Value
	2013		8,870		$	48.99			21,560			$	46.23
	2012		15,303		35.94				—			—
	2011		14,655		37.53				—			—
	Performance Shares
	In 2013, 2012, and 2011, the Compensation Committee granted performance share awards to certain management employees. Half of the performance share awards will be paid out in Common Stock based on UNS Energy’s compound annualized Total Shareholder Return (TSR) relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period. The grant date fair values of these awards were derived based on a Monte Carlo simulation. 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 will be paid out in Common Stock based on cumulative net income (CNI) for the three-year performance period. The grant date fair values of these awards were the closing Common Stock market prices on the dates of grant. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.
	The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.
	See summary of performance shares awarded in the table below:
					Grant Date Fair Value
	Award Year		Performance Shares		TSR-Based Award				CNI-Based Award
	2013		43,120		$	45.54			$	46.23
	2012		80,140		32.71				36.4
	2011		80,440		33.73				36.58
	At December 31, 2013, upon completion of the three-year performance period, 68,158 shares were earned and vested based on goal attainment at 150% of target for the awards based on TSR and 57.8% of target for the awards based on CNI; 28,682 shares were unearned and forfeited. The vested performance shares also earned 8,521 in dividend equivalent shares.
	See summary of restricted stock units and performance shares current year activity in the table below:
			Restricted Stock Units						Performance Shares
			Shares		Weighted				Shares			Weighted
			(000s)		Average				(000s)			Average
					Grant  Date							Grant  Date
					Fair Value							Fair Value
	Non-vested, Beginning of Year		15		$	35.94			145			$	34.83
	Granted		31		47.04				52			44.94
	Vested		(16	)	36.27				(52	)		35.35
	Forfeited		(2	)	46.23				(32	)		37.57
	Non-vested, End of Year		28		47.12				113			38.45
	The total fair value of restricted stock units and performance shares vested were as follows:
		Restricted Stock Units											Performance Shares
		2013			2012				2011				2013				2012				2011
	Thousands of Dollars
Total Fair Value of Shares Vested	$	574		$	550			$	495			$	2,387			$	2,377			$	1,069
Common Stock shares totaling 57,253 in 2013, 31,058 in 2012, and 56,705 in 2011 were issued with no additional increase in equity as the expense was previously recognized over the vesting period.
SHARE-BASED COMPENSATION EXPENSE
In 2013, UNS Energy and TEP recorded share-based compensation expense of $3 million. In 2012 and 2011, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. No share-based compensation was capitalized as part of the cost of an asset. UNS Energy did not realize a tax deduction from the exercise of share-based payment arrangements in 2013 or 2011. In 2012, the actual tax deduction realized from the exercise of share-based payment arrangements totaled less than $0.5 million.
At December 31, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $3 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At December 31, 2013, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.

UNS_ENERGY_EARNINGS_PER_SHARE

UNS ENERGY EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 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 notes were converted to Common Stock.
	The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	Numerator:
	Net Income	$	127,478		$	90,919		$	109,975
	Income from Assumed Conversion of Convertible Senior Notes (1)	—			1,100			4,390
	Adjusted Net Income Available for Diluted Common Stock Outstanding	$	127,478		$	92,019		$	114,365
		Thousands of Shares
	Denominator:
	Weighted Average Shares of Common Stock Outstanding:
	Common Shares Issued	41,446			40,212			36,780
	Fully Vested Deferred Stock Units	172			150			129
	Participating Securities	—			—			53
	Total Weighted Average Common Stock Outstanding and Participating Securities—Basic	41,618			40,362			36,962
	Effect of Dilutive Securities:
	Convertible Senior Notes (1)	—			1,062			4,281
	Options and Stock Issuable Under Share-Based Compensation Plans	357			331			366
	Total Weighted Average Common Stock Outstanding —Diluted	41,975			41,755			41,609
	-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:
		Years Ended December 31,
		2013		2012			2011
		Thousands of Shares
	Stock Options	—		50			153
	Restricted Stock Units	6		—			—
	Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6		50			153

STOCKHOLDERS_EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
STOCKHOLDERS' EQUITY	'
	STOCKHOLDERS’ EQUITY
	DIVIDEND LIMITATIONS
	UNS Energy
	UNS Energy’s ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium, and UED, as well as compliance with various debt covenant requirements. UNS Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2013; therefore, TEP and the other subsidiaries were not restricted from paying dividends.
	The merger agreement with Fortis allows UNS Energy's Board of Directors to authorize quarterly dividends of up to $0.48 per share until the merger is completed, including a pro rata dividend determined by the number of days from the last declared record date to the date the merger is completed.
	In February 2014, UNS Energy declared a first quarter dividend to shareholders of $0.48 per share of UNS Energy Common Stock. The dividend, totaling approximately $20 million, will be paid on March 25, 2014, to common shareholders of record as of March 13, 2014.
	In the first half of 2012, $147 million of the Convertible Senior Notes outstanding were converted into approximately 4.3 million shares of UNS Energy Common Stock increasing common stock equity by $147 million.
	TEP
	TEP paid dividends to UNS Energy of $40 million in 2013 and $30 million in 2012. TEP paid no dividends to UNS Energy in 2011.
	UNS Energy made no capital contributions to TEP in 2013 or 2012, and made capital contributions to TEP of $30 million in 2011.

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 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
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	Net Income	$	127,478		$	90,919		$	109,975
	Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
	Depreciation Expense	149,615			141,303			133,832
	Amortization Expense	27,557			35,784			30,983
	Depreciation and Amortization Recorded to Fuel and O&M Expense	7,288			6,622			6,140
	Amortization of Deferred Debt-Related Costs included in Interest Expense	3,050			3,000			3,985
	Provision for Retail Customer Bad Debts	2,263			2,767			2,072
	Use of Renewable Energy Credits for Compliance	17,706			5,935			5,695
	Deferred Income Taxes	83,501			60,264			75,515
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—			—
	Pension and Retiree Expense	22,783			21,856			21,202
	Pension and Retiree Funding	(29,161		)	(29,058		)	(28,775		)
	Share-Based Compensation Expense	3,399			2,573			2,599
	Allowance for Equity Funds Used During Construction	(6,190		)	(3,464		)	(4,496		)
	Increase (Decrease) to Reflect PPFAC/PGA Recovery	(16,313		)	32,246			(4,932		)
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
	Competition Transition Charge Revenue Refunded	—			—			(35,958		)
	Partial Write-off of Tucson to Nogales Transmission Line	—			4,668			—
	Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
	Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(6,338		)	3,369			2,743
	Materials and Fuel Inventory	16,197			(39,429		)	(20,864		)
	Accounts Payable	3,223			595			8,792
	Income Taxes	(15,868		)	(11,557		)	(2,739		)
	Interest Accrued	4,875			6,922			14,344
	Taxes Other Than Income Taxes	1,941			(58		)	2,857
	Current Regulatory Liabilities	11,124			(684		)	2,644
	Other	20,421			11,486			19,097
	Net Cash Flows – Operating Activities	$	420,512		$	348,109		$	337,320
		TEP
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	Net Income	$	101,342		$	65,470		$	85,334
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	118,076			110,931			104,894
	Amortization Expense	31,294			39,493			34,650
	Depreciation and Amortization Recorded to Fuel and O&M Expense	6,219			5,384			4,509
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,452			2,227			2,378
	Provision for Retail Customer Bad Debts	1,678			1,871			1,447
	Use of RECs for Compliance	15,990			5,071			5,190
	Deferred Income Taxes	69,950			45,232			59,309
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—			—
	Pension and Retiree Expense	19,878			19,289			18,816
	Pension and Retiree Funding	(27,636		)	(25,899		)	(25,878		)
	Share-Based Compensation Expense	2,709			2,029			2,027
	Allowance for Equity Funds Used During Construction	(4,526		)	(2,840		)	(3,842		)
	Increase (Decrease) to Reflect PPFAC Recovery	(12,458		)	31,113			(6,165		)
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
	Competition Transition Charge Revenue Refunded	—			—			(35,958		)
	Partial Write-off of Tucson to Nogales Transmission Line	—			4,484			—
	Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
	Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
	Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,041		)	(871		)	4,809
Materials and Fuel Inventory	16,145			(38,384		)	(19,789		)
Accounts Payable	334			1,115			14,561
Income Taxes	(10,790		)	(11,421		)	(5,582		)
Interest Accrued	4,859			8,055			14,268
Taxes Other Than Income Taxes	1,425			905			2,282
Current Regulatory Liabilities	3,331			(3,040		)	303
Other	19,711			5,655			18,122
Net Cash Flows – Operating Activities	$	346,191		$	267,919		$	268,294
NON-CASH TRANSACTIONS
In 2013, the following non-cash transactions occurred:
•	TEP recorded an increase of $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in December 2014 and January 2015. See Note 6.
•	In November 2013, TEP issued $100 million of tax-exempt bonds and the proceeds were deposited with the trustee to redeem debt in December 2013. TEP had no cash receipts or payments as a result of this transaction. See Note 6.
•	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 6.
In 2012, the following non-cash transactions occurred:
•	UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Shares. See Note 6; and
•	TEP redeemed $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. See Note 6.
Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
(Decrease)/Increase to Utility Plant Accruals(1)	$	4,995		$	4,813		$	(2,741	)
Net Cost of Removal of Interim Retirements(2)	25,182			35,983			31,626
Capital Lease Obligations(3)	9,039			11,967			15,162
Asset Retirement Obligations(4)	8,064			789			7,638
(1)	The non-cash additions to Utility Plant represent accruals for capital expenditures.
(2)	The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.
(3)	The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.
(4)	The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

FAIR_VALUE_MEASUREMENTS_DERIVA

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS	'
	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
	We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity.
	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
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	14			$	14			$	—			$	—			$	—		$	14
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	7				—				3				4				(5		)	2
	Total Assets	45				16				25				4				(5		)	40
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(7		)		—				(2		)		(5		)		5			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
	Total Liabilities	(15		)		—				(9		)		(6		)		5			(10		)
	Net Total Assets (Liabilities)	$	30			$	16			$	16			$	(2	)		$	—		$	30
		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
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—			$	—			$	—		$	—
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	2				—				1				1				(1		)	1
	Total Assets	26				2				23				1				(1		)	25
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(2		)		—				—				(2		)		1			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
	Total Liabilities	(10		)		—				(7		)		(3		)		1			(9		)
	Net Total Assets (Liabilities)	$	16			$	2			$	16			$	(2	)		$	—		$	16
		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 or Level 3), 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
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
The interest rate swap agreements expire through January 2020. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 16. 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
	Years Ended December 31,
	2013				2012				2011				2013				2012			2011
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	(9	)		$	(21	)		$	2			$	—			$	(6	)	$	2
Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At December 31, 2013, UNS Energy and TEP have energy contracts that will settle through the fourth quarter of 2016.
Derivative Volumes
The volumes associated with our energy contracts were as follows:
	UNS Energy						TEP
	December 31, 2013			December 31, 2012			December 31, 2013			December 31, 2012
Power Contracts GWh	1,583			2,228			779			820
Gas Contracts GBtu	33,371			17,851			9,615			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
			31-Dec-13										Range of
	Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
			Millions of Dollars
Forward Contracts(1)	Market approach		$	1			$	(4	)		Market price per MWh		$	26.54		-	$	51.75
Option Contracts(2)	Option model		3				(2		)		Market Price per MMbtu		$	3.87		-	$	4.32
											Gas Volatility		25.05		%	-	35.07		%
Level 3 Energy Contracts			$	4			$	(6	)
(1)	TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.
(2)	TEP comprises less than $1 million of the option contract assets.
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:
	UNS Energy				TEP
	Millions of Dollars
Balances at December 31, 2012	$	(5	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(1		)		(2		)
Settlements	4				—
Balances at December 31, 2013	$	(2	)		$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)		$	(1	)
	UNS Energy				TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)		$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(5		)		1
Settlements	10				(1		)
Balances at December 31, 2012	$	(5	)		$	—
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
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Electric, or UNS Gas; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.
We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.
Material adverse changes could trigger credit risk-related contingent features. At December 31, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $21 million for UNS Energy and $5 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $21 million for UNS Energy and $5 million for TEP.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:
•	The carrying amounts of our current 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:
			31-Dec-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				25				36				23
Liabilities:
Long-Term Debt
UNS Energy	Level 2		1,507				1,521				1,498				1,583
TEP	Level 2		1,223				1,214				1,223				1,271

CHANGES_IN_ACCUMULATED_OTHER_C

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT	12 Months Ended
	Dec. 31, 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
		Year Ended December 31, 2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(1,377	)	$	(1,166	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(2,429		)	(2,429		)	Interest Expense Capital Leases
	Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
	Tax Benefit	1,801			1,718
	Realized Losses on Cash Flow Hedges, Net of Taxes	(2,752		)	(2,624		)
	Amortization of SERP and Defined Benefit Plans
	Prior Service Costs	(1,488		)	(1,488		)	Other Expense
	Tax Benefit	572			572
	Amortization, Net of Taxes	(916		)	(916		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(3,668	)	$	(3,540	)

RECENTLY_ISSUED_ACCOUNTING_PRO

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	12 Months Ended
	Dec. 31, 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, we do not expect any material changes in the presentations of our other financial statements.

QUARTERLY_FINANCIAL_DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
QUARTERLY FINANCIAL DATA	'
	QUARTERLY FINANCIAL DATA (UNAUDITED)
	Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the summer while UNS Gas’ sales generally peak during the winter. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
		UNS Energy
		First			Second		Third		Fourth
		Thousands of Dollars
		(Except Per Share Amounts)
	2013
	Operating Revenue	$	332,141		$	365,217	$	437,041	$	350,161
	Operating Income	39,895			60,803		129,765		41,033
	Net Income	11,345			34,618		67,990		13,525
	Basic EPS	0.27			0.83		1.63		0.32
	Diluted EPS	0.27			0.83		1.62		0.32
	2012
	Operating Revenue	$	315,387		$	363,998	$	434,108	$	348,273
	Operating Income (1)	34,403			68,065		106,409		42,918
	Net Income	6,476			26,273		50,664		7,506
	Basic EPS	0.17			0.65		1.22		0.18
	Diluted EPS	0.17			0.64		1.21		0.18
	EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.
		TEP
		First			Second		Third		Fourth
		Thousands of Dollars
	2013
	Operating Revenue	$	247,751		$	304,263	$	371,239	$	273,437
	Operating Income	22,747			53,433		123,177		31,014
	Net Income	1,478			30,787		64,167		4,910
	2012
	Operating Revenue	$	223,978		$	299,419	$	366,910	$	271,353
	Operating Income (1)	17,898			58,211		94,079		30,299
	Net Income (Loss)	(1,461		)	21,910		44,569		452
	(1) Immaterial variances from quarterly amounts previously reported result from line item reclassifications.

SCHEDULE_II_Valuation_and_Qual

SCHEDULE II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
SCHEDUEL II- VALUATION & QUALIFYING ACCOUNTS	'
	Schedule II—Valuation and Qualifying Accounts – UNS Energy
	Allowance for Doubtful Accounts (1)	Beginning			Additions-			Deductions			Ending
		Balance			Charged  to						Balance
					Income
		Millions of Dollars
	Year Ended December 31,
	2013	$	7		$	2		$	2		$	7
	2012	16			4			13			7
	2011	13			5			2			16
	Other Reserves (2)	Beginning Balance			Ending Balance
		Millions of Dollars
	Year Ended December 31,
	2013	$	9		$	6
	2012	6			9
	2011	4			6
	Schedule II—Valuation and Qualifying Accounts—TEP
	Allowance for Doubtful Accounts (1)		Beginning			Additions-			Deductions			Ending
			Balance			Charged  to						Balance
						Income
			Millions of Dollars
	Year Ended December 31,
	2013		$	5		$	2		$	2		$	5
	2012		14			3			12			5
	2011		11			4			1			14
	Other Reserves (2)	Beginning Balance			Ending Balance
		Millions of Dollars
	Year Ended December 31,
	2013	$	8		$	4
	2012	4			8
	2011	3			4
	(1)	TEP, UNS Electric, and UNS Gas record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.
	(2)	As the Other reserves are not individually significant, additions and deductions need not be disclosed. Principally reserves for sales tax audits, litigation matters, and damages billable to third parties.

NATURE_OF_OPERATIONS_AND_SUMMA1

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Nature of Operations	'
	NATURE OF OPERATIONS
	UNS Energy Corporation (UNS Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
	TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of December 31, 2013. TEP generates, transmits and distributes electricity to approximately 413,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).
	UES wholly-owns two regulated utilities: UNS Electric, Inc. (UNS Electric) and UNS Gas, Inc. (UNS Gas). UNS Electric is a regulated utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.
	UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2013.
	Our business is comprised of three reporting segments – TEP, UNS Electric, and UNS Gas.
	References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
Basis Of Presentation	'
	BASIS OF PRESENTATION
	UNS Energy's consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 3. The consolidated financial statements include the accounts of UNS Energy and all of its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated if recovery from ratepayers is probable. See Note 4. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income.
Use of Accounting Estimates	'
	USE OF ACCOUNTING ESTIMATES
	Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect:
	•	Assets and liabilities on our balance sheets at the dates of the financial statements;
	•	Our disclosures about contingent assets and liabilities at the dates of the financial statements; and
	•	Our revenues and expenses in our income statements during the periods presented.
	Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.
Accounting for Regulated Operations	'
	ACCOUNTING FOR REGULATED OPERATIONS
	We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through FERC-approved transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future billing reductions.
	Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 3.
	TEP, UNS Electric, and UNS Gas apply regulatory accounting as the following conditions exist:
	•	An independent regulator sets rates;
	•	The regulator sets the rates to recover the specific enterprise’s costs of providing service; and
	•	Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.
Recently Adopted Accounting Pronouncements	'
	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 15.
	•	Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 16.
Cash and Cash Equivalents	'
	CASH AND CASH EQUIVALENTS
	We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
Restricted Cash	'
	RESTRICTED CASH
	Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets
Utility Plant	'
	UTILITY PLANT
	Utility Plant includes the business property and equipment that supports electric and gas services, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction.
	We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statements as costs are incurred.
	When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage value. There is no income statement impact.
AFUDC and Capitalized Interest	'
	AFUDC and Capitalized Interest
	AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.
	The average AFUDC rates on regulated construction expenditures are included in the table below:
		2013		2012		2011
	TEP	7.38	%	7.22	%	6.72	%
	UNS Electric	8.07	%	7.89	%	8.18	%
	UNS Gas	7.89	%	7.95	%	8.32	%
	UNS Energy did not capitalize interest related to non-regulated construction activity in 2013 or 2012. UNS Energy capitalized interest on non-regulated construction activity at a rate of 3.30% for 2011.
Depreciation	'
	Depreciation
	We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 and Note 5. The Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC)
TEP Utility Plant Under Capital Leases	'
	TEP Utility Plant Under Capital Leases
	TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense—Capital Leases. The lease terms are described in Note 6.
Computer Software Costs	'
	Computer Software Costs
	We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.
Investments in Lease Debt and Equity	'
	INVESTMENTS IN LEASE DEBT AND EQUITY
	TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 15. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to the equity holders.
	TEP accounts for its equity interest in the Springerville Unit 1 Lease trust using the equity method.
Asset Retirement Obligations	'
	ASSET RETIREMENT OBLIGATIONS
	TEP and UNS Electric have identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense, and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.
	Depreciation rates for all of our utilities also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.
Evaluation of Assets for Impairment	'
	EVALUATION OF ASSETS FOR IMPAIRMENT
	We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.
Deferred Financing Costs	'
	DEFERRED FINANCING COSTS
	We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
	We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.
Operating Revenues	'
	OPERATING REVENUES
	We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity and gas sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.
	For purchased power and wholesale sales contracts that are not settled with energy, TEP and UNS Electric net the sales contracts with the purchase power contracts and reflect the net amount as Electric Wholesale Sales. The corresponding cash receipts are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales, while cash payments are recorded as Purchased Energy/Power Costs Paid.
	TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned.
	The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) associated with energy sales that no longer occur due to EE Standards and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.
Allowance for Doubtful Accounts	'
	ALLOWANCE FOR DOUBTFUL ACCOUNTS
	We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions.
Inventory	'
	INVENTORY
	We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.
Recovery Of Fuel And Purchased Energy Costs	'
	FUEL AND PURCHASED ENERGY COST RECOVERY MECHANISMS
	TEP and UNS Electric Purchased Power and Fuel Adjustment Clause
	TEP and UNS Electric recover actual fuel, purchased power and transmission costs incurred to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts the PPFAC rate at which TEP and UNS Electric recover these costs. The difference between costs recovered through rates and actual fuel, purchased power and transmission costs prudently incurred to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 3.
	UNS Gas Purchased Gas Adjustor
	UNS Gas recovers actual gas costs incurred through a Purchased Gas Adjustor (PGA) mechanism that adjusts monthly. Gas cost over-recoveries are deferred as regulatory liabilities and under-recoveries are deferred as regulatory assets. See Note 3.
Renewable Energy Credits	'
	RENEWABLE ENERGY and ENERGY EFFICIENCY PROGRAMS
	The ACC’s Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The utilities must file annual RES implementation plans for review and approval by the ACC. The approved cost of carrying out those plans is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates.
	TEP, UNS Electric, and UNS Gas are required to implement cost-effective Demand-Side Management (DSM) programs to comply with the ACC’s Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail kWh savings equal to22% by 2020. The Gas EE Standards require increasing annual targeted retail therm sales equal to 6% by 2020.
	Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP and UNS Electric recognize RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. Similarly, UNS Gas recognizes DSM surcharge revenue in Gas Retail Sales.
	RENEWABLE ENERGY CREDITS
	The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP or UNS Electric purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC.
	When RECs are purchased, TEP and UNS Electric record the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount. See Note 3.
Income Taxes	'
	INCOME TAXES
	Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized.
	Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.  Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.
	Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 3.
	We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and are deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises.
	Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.
Taxes Other Than Income Taxes	'
	TAXES OTHER THAN INCOME TAXES
	We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies on the balance sheet for these taxes and assessments. These amounts are not reflected in the income statements.
Derivative Instruments	'
	DERIVATIVE INSTRUMENTS
	We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.
	Cash Flow Hedges
	TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. UNS Electric uses a cash flow hedge to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP and UNS Electric account for cash flow hedges as follows:
	•	The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and
	•	When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.
	We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.
	Energy Contracts - Regulatory Recovery
	TEP, UNS Electric and UNS Gas are authorized to recover the prudent costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC or PGA mechanism.
	Master Netting Agreements
	We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.
	Normal Purchases and Normal Sales
	We enter into forward energy purchase and sales contracts, including call options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.
Pension and Other Retiree Benefits	'
	PENSION AND OTHER RETIREE BENEFITS
	We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees.
	We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees.
	Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
	Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 10.

NATURE_OF_OPERATIONS_AND_SUMMA2

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
AFUDC Rates	'
	The average AFUDC rates on regulated construction expenditures are included in the table below:
		2013		2012		2011
	TEP	7.38	%	7.22	%	6.72	%
	UNS Electric	8.07	%	7.89	%	8.18	%
	UNS Gas	7.89	%	7.95	%	8.32	%
Summary Of Average Annual Depreciation Rates For All Utility Plants	'
	Below are the summarized average annual depreciation rates for all utility plant:
		2013		2012		2011
	TEP	3.16	%	3.22	%	3.14	%
	UNS Electric	3.94	%	3.99	%	4.02	%
	UNS Gas	2.63	%	2.69	%	2.84	%

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Summary of PPFAC Rates	'
	The tables below summarize TEP’s and UNS Electric’s PPFAC rates:
		TEP
		2013						2012
		July - December			January - June			April - December			January - March
		Cents per kWh
	PPFAC Rate	0.14			0.77			0.77			0.53
	Competition Transition Charge (1)	—			—			—			(0.53	)
	Net TEP PPFAC Rate	0.14			0.77			0.77			—
	(1)	TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.
		UNS Electric
		2013									2012
		September - December			June - August			January - May			June - December		January - May
		Cents per kWh
	PPFAC Rate	(0.40	)		(0.92	)		(1.44	)		(1.44	)	(0.88	)
Regulatory Assets and Liabilities	'
	The following tables summarize regulatory assets and liabilities:
		31-Dec-13
		TEP				UNS				UNS			UNS
						Electric				Gas			Energy
		Millions of Dollars
	Regulatory Assets—Current
	Property Tax Deferrals (1)	$	20			$	—			$	—		$	20
	Derivative Instruments (Note 15)	1				—				—			1
	San Juan Mine Fire Cost Deferral (2)	10				—				—			10
	PPFAC (2)	4				10				—			14
	DSM and LFCR (2)	3				—				—			3
	Other Current Regulatory Assets (3)	5				—				—			5
	Total Regulatory Assets—Current	43				10				—			53
	Regulatory Assets—Noncurrent
	Pension and Other Retiree Benefits (Note 10)	75				3				2			80
	Income Taxes Recoverable through Future Revenues (4)	22				3				—			25
	PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	25				—				—			25
	Discontinued Nogales Transmission Project (6)	5				—				—			5
	Other Regulatory Assets (3)	14				2				—			16
	Total Regulatory Assets—Noncurrent	141				8				2			151
	Regulatory Liabilities—Current
	PGA (2)	—				—				(15		)	(15		)
	RES (2)	(22		)		(9		)		—			(31		)
	Other Current Regulatory Liabilities	(2		)		(6		)		—			(8		)
	Total Regulatory Liabilities—Current	(24		)		(15		)		(15		)	(54		)
	Regulatory Liabilities—Noncurrent
	Net Cost of Removal for Interim Retirements (7)	(254		)		(12		)		(26		)	(292		)
	Income Taxes Payable through Future Rates	(5		)		—				(1		)	(6		)
	Deferred Investment Tax Credit (8)	(4		)		—				—			(4		)
	Total Regulatory Liabilities—Noncurrent	(263		)		(12		)		(27		)	(302		)
	Total Net Regulatory Assets (Liabilities)	$	(103	)		$	(9	)		$	(40	)	$	(152	)
		31-Dec-12
		TEP				UNS				UNS			UNS
						Electric				Gas			Energy
		Millions of Dollars
	Regulatory Assets—Current
	Property Tax Deferrals (1)	$	18			$	—			$	—		$	18
	Derivative Instruments (Note 15)	2				6				3			11
	PPFAC (2)	7				8				—			15
	DSM (2)	5				—				—			5
	Other Current Regulatory Assets (3)	2				—				1			3
	Total Regulatory Assets—Current	34				14				4			52
	Regulatory Assets—Noncurrent
	Pension and Other Retiree Benefits (Note 10)	130				5				4			139
	Income Taxes Recoverable through Future Revenues (4)	8				2				—			10
	PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	22				—				—			22
	Discontinued Nogales Transmission Project (6)	5				—				—			5
	Other Regulatory Assets (3)	13				1				1			15
	Total Regulatory Assets—Noncurrent	178				8				5			191
	Regulatory Liabilities—Current
	PGA (2)	—				—				(17		)	(17		)
	RES (2)	(19		)		(4		)		—			(23		)
	Other Current Regulatory Liabilities	(2		)		(1		)		(1		)	(4		)
	Total Regulatory Liabilities—Current	(21		)		(5		)		(18		)	(44		)
	Regulatory Liabilities—Noncurrent
	Net Cost of Removal for Interim Retirements (7)	(231		)		(11		)		(25		)	(267		)
	Income Taxes Payable through Future Rates	(5		)		—				(1		)	(6		)
	Deferred Investment Tax Credit (8)	(5		)		—				—			(5		)
	Other Regulatory Liabilities	—				(1		)		—			(1		)
	Total Regulatory Liabilities—Noncurrent	(241		)		(12		)		(26		)	(279		)
	Total Net Regulatory Assets (Liabilities)	$	(50	)		$	5			$	(35	)	$	(80	)
	Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets below. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets.
	(1)	Property Tax is recovered over approximately a six-month period as costs are paid, rather than as costs are accrued.
(2)	See Cost Recovery Mechanisms discussion above.
(3)	TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).
(4)	Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.
(5)	Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
(6)	TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.
Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers, as described below:
(7)	Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.
(8)	The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

BUSINESS_SEGMENTS_Tables

BUSINESS SEGMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Reconciling Adjustments of Income Statement Items in Consolidation	'
	We disclose selected financial data for our reportable segments in the following tables:
		Reportable Segments
		TEP			UNS Electric			UNS Gas			Other (2)			Reconciling			UNS
														Adjustments			Energy
		Millions of Dollars
	2013
	Income Statement
	Operating Revenues-External	$	1,180		$	174		$	131		$	2		$	(2	)	$	1,485
	Operating Revenues-Intersegment (1)	17			2			3			17			(39		)	—
	Depreciation and Amortization	149			19			9			—			—			177
	Interest Income	—			1			—			—			—			1
	Interest Expense	79			7			6			1			—			93
	Income Tax Expense	48			7			7			(4		)	—			58
	Net Income	101			12			11			3			—			127
	Cash Flow Statement
	Capital Expenditures	(253		)	(56		)	(17		)	—			—			(326		)
	Balance Sheet
	Total Assets	3,556			404			311			1,194			(1,192		)	4,273
		Reportable Segments
		TEP			UNS Electric			UNS Gas			Other (2)			Reconciling			UNS
														Adjustments			Energy
		Millions of Dollars
	2012
	Income Statement
	Operating Revenues-External	$	1,145		$	189		$	129		$	—		$	(1	)	$	1,462
	Operating Revenues-Intersegment (1)	17			1			4			18			(40		)	—
	Depreciation and Amortization	150			18			9			—			—			177
	Interest Income	—			—			—			1			—			1
	Interest Expense	88			8			6			3			—			105
	Income Tax Expense	39			11			6			—			—			56
	Net Income	65			17			9			—			—			91
	Cash Flow Statement
	Capital Expenditures	(253		)	(38		)	(16		)	—			—			(307		)
	Balance Sheet
	Total Assets	3,461			370			310			1,121			(1,122		)	4,140
	2011
	Income Statement
	Operating Revenues-External	$	1,141		$	188		$	149		$	—		$	1		$	1,479
	Operating Revenue-Intersegment (1)	15			2			2			23			(42		)	—
	Depreciation and Amortization	140			17			8			1			(1		)	165
	Interest Income	4			—			—			1			—			5
	Interest Expense	89			7			7			9			—			112
	Income Tax Expense	52			11			7			(1		)	(2		)	67
	Net Income	85			18			10			—			(3		)	110
	Cash Flow Statement
	Capital Expenditures	(352		)	(96		)	(13		)	(34		)	121			(374		)
	(1)	Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.
	(2)	Other includes the UNS Energy and UES holding companies, Millennium, and UED.

UTILITY_PLANT_AND_JOINTLYOWNED1

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2013
Regulatory Operations [Abstract]	'
Public Utility Property, Plant, and Equipment	'
	The following table shows Utility Plant in Service by major class:
		UNS Energy								TEP
		December 31,								December 31,
		2013				2012				2013				2012
		Millions of Dollars
	Plant in Service:
	Electric Generation Plant	$	1,974			$	1,932			$	1,889			$	1,847
	Electric Transmission Plant	912				842				825				796
	Electric Distribution Plant	1,529				1,495				1,298				1,271
	Gas Distribution Plant	252				240				—				—
	Gas Transmission Plant	18				18				—				—
	General Plant	356				347				312				309
	Intangible Plant - Software Costs (1) (2)	142				124				141				123
	Intangible Plant - Other	5				5				—				—
	Electric Plant Held for Future Use	4				3				3				2
	Total Plant in Service	$	5,192			$	5,006			$	4,468			$	4,348
	Utility Plant under Capital Leases(3)	$	638			$	583			$	638			$	583
	(1)	Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.
	(2)	The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.
	(3)	In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.
Amount Of Lease Expense Incurred Related Capital Leases	'
	The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:
		Years Ended December 31,
		2013				2012				2011
		Millions of Dollars
	Lease Expense:
	Interest Expense – Included in:
	Capital Leases	25				$	34			$	40
	Operating Expenses – Fuel	2				3				4
	Other Expense	—				—				1
	Amortization of Capital Lease Assets – Included in:
	Operating Expenses – Fuel	5				4				3
	Operating Expenses – Amortization	15				14				14
	Total Lease Expense	$	47			$	55			$	62
Depreciable Lives Of Utility Plant In Service	'
	Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2013, were as follows:
		TEP
		31-Dec-13
		Annual Depreciation Rate (5)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Electric Generation Plant (1)	3.31%		22
	Electric Transmission Plant	1.48%		32
	Electric Distribution Plant (1)	2.08%		35
	General Plant (1)	5.48%		11
	Intangible Plant (2)	Various		Various
		UNS Electric
		31-Dec-13
		Annual Depreciation Rate (5)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Electric Generation Plant	2.56%		36
	Electric Transmission Plant	3.36%		19
	Electric Distribution Plant	3.97%		15
	General Plant	8.01%		7
	Intangible Plant (3)	Various		Various
		UNS Gas
		31-Dec-13
		Annual Depreciation Rate (5)		Average Remaining Life in Years
	Major Class of Utility Plant in Service:
	Gas Generation Plant	2.37%		41
	Gas Transmission Plant	1.54%		54
	General Plant	4.38%		7
	Intangible Plant (4)	Various		Various
	-1	In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.
	(2)	The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life based on either the average lives of 3 to 5 years for smaller application software or remaining lives ranging from 5 to 19 years for large enterprise software.
	(3)	UNS Electric's intangible plant primarily represents capitalized interconnection costs, which are amortized based on either an average life of 23 years or a remaining life of 35 years.
	(4)	UNS Gas' intangible plant consists of miscellaneous intangible assets, which are amortized over an average life of either 15 or 25 years.
	(5)	The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.
Schedule of Jointly Owned Utility Plants	'
	At December 31, 2013, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:
		Ownership Percentage		Plant in Service				Construction Work in				Accumulated Depreciation				Net Book Value
								Progress
				Millions of Dollars
	San Juan Units 1 and 2	50.00%		$	448			$	6			$	230			$	224
	Navajo Units 1, 2, and 3	7.50%		152				1				110				43
	Four Corners Units 4 and 5	7.00%		101				2				75				28
	Luna Energy Facility	33.30%		53				—				2				51
	Transmission Facilities	Various		330				43				190				183
	Total			$	1,084			$	52			$	607			$	529
Schedule of Asset Retirement Obligations	'
	The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:
		UNS Energy
		December 31,
		2013				2012
		Millions of Dollars
	Beginning Balance	$	14			$	13
	Liabilities Incurred	1				—
	Accretion Expense or Regulatory Deferral	1				1
	Revisions to the Present Value of Estimated Cash Flows (1)	7				—
	Ending Balance	$	23			$	14
	-1	Primarily related to changes in expected retirement dates of generating facilities.
	The table above primarily reflects TEP's ARO obligations. UNS Electric's ARO obligations were less than $1 million at December 31, 2013 and 2012.

DEBT_CREDIT_FACILITIES_AND_CAP1

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Interest Rates on TEP's Variable Rate	'
	The following table shows interest rates on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents:
		Years Ended December 31,
		2013		2012		2011
	Interest Rates on Bonds:
	Average Interest Rate	0.10%		0.17%		0.18%
	Range of Average Weekly Rates	0.06% - 0.25%		0.06% - 0.26%		0.05% - 0.34%
Effect Of Fixing Interest Rates On Amortizing Principal Balances Of Swaps	'
	The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:
	Lease Debt Outstanding at December 31, 2013	Fixed			LIBOR
		Rate			Spread
	Swap 1 - Notional Amount $33 million - Effective Date June 2006	5.77	%		1.75	%
	Swap 2 - Notional Amount $16 million - Effective Date May 2009	3.18	%		1.75	%
	Swap 3 - Notional Amount $6 million - Effective Date May 2009	3.32	%		1.75	%
	TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 15.
Maturities of Long-term Debt	'
	Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
		TEP				TEP			TEP			UNS		UNS		UNS		Total
		Long-Term				Capital			Total			Electric		Gas		Energy
		Debt				Lease										Parent
		Maturities (1)				Obligations										Company
		Millions of Dollars
	2014	$	—			$	214		$	214		$	—	$	—	$	—	$	214
	2015	—				69			69			80		50		—		199
	2016	78				17			95			—		—		54		149
	2017	—				18			18			—		—		—		18
	2018	100				11			111			—		—		—		111
	Total 2014 – 2018	178				329			507			80		50		54		691
	Thereafter	1,046				30			1,076			50		50		—		1,176
	Less: Imputed Interest	—				(42		)	(42		)	—		—		—		(42		)
	Total	$	1,224			$	317		$	1,541		$	130	$	100	$	54	$	1,825
	(1)	$115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Unrecorded Unconditional Purchase Obligations Disclosure	'
	At December 31, 2013, UNS Energy and TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases. UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas:
		UNS Energy Purchase Commitments
		2014		2015			2016			2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	103	$	83		$	80		$	75	$	49	$	345	$	735
	Purchased Power	75		17			—			—		—		—		92
	Transmission	7		13			12			12		11		27		82
	Renewable Power Purchase Agreements	36		37			37			37		37		485		669
	RES Performance-Based Incentives	9		9			9			9		9		85		130
	Operating Leases	4		4			3			2		2		14		29
	Total Purchase Commitments	$	234	$	163		$	141		$	135	$	108	$	956	$	1,737
	At December 31, 2013, TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases:
		TEP Purchase Commitments
		2014		2015			2016			2017		2018		Thereafter		Total
		Millions of Dollars
	Fuel, Including Transportation	$	77	$	63		$	64		$	62	$	36	$	285	$	587
	Purchased Power	27		5			—			—		—		—		32
	Transmission	3		6			6			6		6		21		48
	Renewable Power Purchase Agreements	30		31			31			31		31		410		564
	RES Performance-Based Incentives	8		8			8			8		8		83		123
	Operating Leases	3		3			2			2		2		14		26
	Total Purchase Commitments	$	148	$	116		$	111		$	109	$	83	$	813	$	1,380
Schedule of Environmental Loss Contingencies by Site	'
	TEP's estimated potential costs involved in meeting these rules are:
	Estimated Potential Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)			Sundt (4)
		Millions of Dollars
	Capital - SCR	$	42	$ 180-200		$	35		$	—
	Capital - SNCR	—		35		—			12
	Annual O&M - SCR	1		6		2			—
	Annual O&M - SNCR	—		1		—			6-May
	-1	The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.
	-2	The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 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.
	-3	On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.
	(4) In January 2014, the EPA issued a proposal that would require TEP to either (i) install SNCR by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is expected to issue a final BART determination by July 2014. At December 31, 2013, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.
	In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATs) rule, additional emission control equipment will be required by 2015. The estimated costs include:
	Estimated Emissions Control Costs:	Navajo		Four Corners			Springerville
		Millions of Dollars
	Capital Expenditures - Mercury Emissions Control	$	1	$	1		$	5
	Annual O&M Expenses	1		1			3

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 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
		Years Ended December 31,
		2013			2012				2011			2013			2012			2011
		Millions of Dollars
	Federal Income Tax Expense at Statutory Rate	$	65		$	51			$	62		$	52		$	37		$	48
	State Income Tax Expense, Net of Federal Deduction	8			7				8			7			5			6
	Federal/State Tax Credits	(2		)	(1		)		(3		)	(2		)	(1		)	(2		)
	Allowance for Equity Funds Used During Construction	(2		)	(1		)		(1		)	(1		)	(1		)	(1		)
	Deferred Tax Asset Valuation Allowance	—			—				—			2			—			—
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—				—			(11		)	—			—
	Other	—			—				1			1			(1		)	1
	Total Federal and State Income Tax Expense	$	58		$	56			$	67		$	48		$	39		$	52
Schedule Of Income Tax Reconciliation Table	'
	Income tax expense included in the income statements consists of the following:
		UNS Energy										TEP
		Years Ended December 31,
		2013			2012				2011			2013			2012			2011
		Millions of Dollars
	Current Tax Expense (Benefit):
	Federal	$	(11	)	$	(2	)		$	(7	)	$	(8	)	$	(4	)	$	(5	)
	State	(2		)	(2		)		(2		)	(2		)	(2		)	(2		)
	Total Current Tax Expense (Benefit)	(13		)	(4		)		(9		)	(10		)	(6		)	(7		)
	Deferred Tax Expense (Benefit):
	Federal	61			51				64			47			38			50
	Federal Investment Tax Credits	(1		)	—				(1		)	(1		)	—			(1		)
	State	11			9				13			12			7			10
	Total Deferred Tax Expense (Benefit)	71			60				76			58			45			59
	Total Federal and State Income Tax Expense	$	58		$	56			$	67		$	48		$	39		$	52
Schedule of Deferred Tax Assets and Liabilities	'
	The significant components of deferred income tax assets and liabilities consist of the following:
		UNS Energy							TEP
		December 31,							December 31,
		2013			2012				2013			2012
		Millions of Dollars
	Gross Deferred Income Tax Assets:
	Capital Lease Obligations	$	127		$	141			$	127		$	141
	Net Operating Loss Carryforwards	94			72				104			85
	Customer Advances and Contributions in Aid of Construction	33			34				19			19
	Alternative Minimum Tax Credit	43			43				24			24
	Accrued Postretirement Benefits	23			23				23			23
	Renewable Energy Credit Up-Front Incentive Payments	—			26				—			20
	Emission Allowance Inventory	10			10				10			10
	Unregulated Investment Losses	7			9				—			—
	Other	50			44				44			43
	Total Gross Deferred Income Tax Assets	387			402				351			365
	Deferred Tax Assets Valuation Allowance	(7		)	(7		)		(2		)	—
	Gross Deferred Income Tax Liabilities:
	Plant – Net	(708		)	(648		)		(615		)	(571		)
	Capital Lease Assets – Net	(47		)	(34		)		(47		)	(34		)
	Pensions	(21		)	(23		)		(22		)	(24		)
	PPFAC	(5		)	(6		)		(2		)	(3		)
	Other	(21		)	(15		)		(20		)	(15		)
	Total Gross Deferred Income Tax Liabilities	(802		)	(726		)		(706		)	(647		)
	Net Deferred Income Tax Liabilities	$	(422	)	$	(331	)		$	(357	)	$	(282	)
Summary of Deferred Tax Liability Not Recognized	'
	The net deferred income tax liability on the balance sheet is as follows:
		UNS Energy							TEP
		December 31,							December 31,
		2013			2012				2013			2012
		Millions of Dollars
	Deferred Income Taxes – Current Assets	$	60		$	34			$	64		$	37
	Deferred Income Taxes – Noncurrent Liabilities	(482		)	(365		)		(421		)	(319		)
	Net Deferred Income Tax Liability	$	(422	)	$	(331	)		$	(357	)	$	(282	)
Summary Of Details Of Tax Carryforwards Table	'
	As of December 31, 2013, UNS Energy and TEP had the following carryforward amounts:
		UNS Energy					TEP
		Amount			Expiring Year		Amount				Expiring Year
		Millions of Dollars					Millions of Dollars
	Capital Loss	$	7		2015		$	—			N/A
	Federal Net Operating Loss	266			2031-33		286				2031-33
	State Net Operating Loss	30			2032-33		99				2016-33
	State Credits	5			2016-18		6				2016-18
	Alternative Minimum Tax Credit	43			None		24				None
	Investment Tax Credits	6			2032-33		6				2032-33
Summary of Income Tax Contingencies	'
	A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
		UNS Energy							TEP
		December 31,							December 31,
		2013			2012				2013			2012
		Millions of Dollars
	Unrecognized Tax Benefits, Beginning of Year	$	30		$	29			$	23		$	24
	Additions Based on Tax Positions Taken in the Current Year	2			5				1			3
	Reductions of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(4		)		(22		)	(4		)
	Unrecognized Tax Benefits, End of Year	$	4		$	30			$	2		$	23

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Amounts Recognized in Balance Sheet	'
	The pension and other retiree benefit related amounts (excluding tax balances) included on the UNS Energy balance sheet are:
		Pension Benefits								Other  Retiree
										Benefits
		Years Ended December 31,
		2013				2012				2013			2012
		Millions of Dollars
	Regulatory Pension Asset Included in Other Regulatory Assets	$	75			$	129			$	4		$	10
	Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)		(1		)		(2		)	(2		)
	Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(28		)		(90		)		(63		)	(69		)
	Accumulated Other Comprehensive Loss (related to SERP)	2				4				—			—
	Net Amount Recognized	$	48			$	42			$	(61	)	$	(61	)
	The table above includes accrued pension benefit liabilities for UNS Electric and UNS Gas of approximately $5 million at December 31, 2013 and $9 million at December 31, 2012. The table also includes an other retiree benefit liability of $1 million for UNS Electric and UNS Gas for each period presented.
Schedule of Changes in Projected Benefit Obligations	'
	We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2013 and December 31, 2012. The table below includes TEP’s, UNS Electric’s, and UNS Gas’ plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below:
		Pension Benefits								Other  Retiree
										Benefits
		Years Ended December 31,
		2013				2012				2013			2012
		Millions of Dollars
	Change in Projected Benefit Obligation
	Benefit Obligation at Beginning of Year	$	380			$	319			$	78		$	73
	Actuarial (Gain) Loss	(38		)		51				(5		)	3
	Interest Cost	15				15				3			3
	Service Cost	13				10				3			3
	Benefits Paid	(18		)		(15		)		(4		)	(4		)
	Projected Benefit Obligation at End of Year	352				380				75			78
	Change in Plan Assets
	Fair Value of Plan Assets at Beginning of Year	289				245				7			5
	Actual Return on Plan Assets	29				36				1			1
	Benefits Paid	(18		)		(15		)		(4		)	(4		)
	Employer Contributions (1)	23				23				6			5
	Fair Value of Plan Assets at End of Year	323				289				10			7
	Funded Status at End of Year	$	(29	)		$	(91	)		$	(65	)	$	(71	)
	(1)	TEP made $22 million in pension contributions and $6 million in other retiree benefits contributions in 2013 and $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012. In 2014, UNS Energy expects to contribute $10 million to the pension plans, including $9 million in contributions by TEP.
	The table above includes the following for UNS Electric and UNS Gas:
	•	Pension benefit obligations of $21 million at December 31, 2013 and $23 million at December 31, 2012;
	•	Plan assets of $16 million at December 31, 2013 and $14 million at December 31, 2012; and
	•	A retiree benefit obligation of $1 million at December 31, 2013 and December 31, 2012.
Schedule of Net Periodic Benefit Cost Not yet Recognized	'
	The following table provides the components of UNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:
		Pension Benefits								Other  Retiree
										Benefits
		Years Ended December 31,
		2013				2012				2013			2012
		Millions of Dollars
	Net Loss	$	77			$	133			$	7		$	13
	Prior Service Cost (Benefit)	—				1				(3		)	(3		)
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	'
	The accumulated benefit obligation aggregated for all pension plans is $314 million at December 31, 2013 and $334 million at December 31, 2012.
	Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
		December 31,
		2013			2012
		Millions of Dollars
	Accumulated Benefit Obligation at End of Year	30			334
	Fair Value of Plan Assets at End of Year	16			289
	At December 31, 2012, all four UNS Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets. Due to 2013 contributions, returns on plan assets, and the favorable impact of the increase in the discount rate on the accumulated benefit obligations, only the SERP, which is unfunded, and the UES plan have accumulated benefit obligations in excess of plan assets at December 31, 2013.
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
		Years Ended December 31,
		2013				2012				2011			2013			2012			2011
		Millions of Dollars
	Service Cost	$	13			$	10			$	10		$	4		$	3		$	3
	Interest Cost	15				16				15			3			3			4
	Expected Return on Plan Assets	(20		)		(17		)		(16		)	(1		)	—			—
	Prior Service Cost Amortization	—				—				—			(1		)	—			(1		)
	Actuarial Loss Amortization	9				7				6			1			—			—
	Net Periodic Benefit Cost	$	17			$	16			$	15		$	6		$	6		$	6
	Approximately 21% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)	'
	The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:
		Pension Benefits
		2013								2012						2011
		Regulatory				AOCI				Regulatory			AOCI			Regulatory			AOCI
		Asset								Asset						Asset
		Millions of Dollars
	Current Year Actuarial (Gain) Loss	$	(46	)		$	(1	)		$	30		$	1		$	25		$	(2	)
	Amortization of Actuarial Gain (Loss)	(8		)		—				(7		)	—			(5		)	—
	Total Recognized (Gain) Loss	$	(54	)		$	(1	)		$	23		$	1		$	20		$	(2	)
		Other Retiree Benefits
		2013				2012				2011
		Regulatory				Regulatory				Regulatory
		Asset				Asset				Asset
		Millions of Dollars
	Prior Service Cost (Credit)	$	—			$	—			$	(2	)
	Current Year Actuarial (Gain) Loss	(6		)		2				—
	Amortization of Actuarial (Gain) Loss	(1		)		—				—
	Amortization of Prior Service (Cost) Credit	1				—				1
	Total Recognized (Gain) Loss	$	(6	)		$	2			$	(1	)
	For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $4 million estimated net loss and less than $1 million prior service cost from other regulatory assets and less than $1 million prior service cost from AOCI into net periodic benefit cost in 2014. The estimated prior service benefit for the other retiree benefit plan that will be amortized from other regulatory assets into net periodic benefit cost in 2014 is less than $1.0 million.
Schedule Of Weighted Average Assumptions Used To Determine Benefit Obligations At Year End Table	'
		Pension Benefits				Other Retiree
						Benefits
		2013		2012		2013		2012
	Weighted-Average Assumptions Used to Determine
	Benefit Obligations as of December 31,
	Discount Rate	5.0% - 5.2%		4.1%-4.3%		4.70%		3.80%
	Rate of Compensation Increase	3.00%		3.00%		N/A		N/A
Schedule Of Weighted Average Assumptions Used To Determine Net Periodic Benefit Cost Table	'
		Pension Benefits						Other Retiree Benefits
		2013		2012		2011		2013		2012		2011
	Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
	Discount Rate	4.1%-4.3%		4.9% - 5.0%		5.5% - 5.6%		3.80%		4.70%		5.20%
	Rate of Compensation Increase	3.00%		3.00%		3.0% - 5.0%		N/A		N/A		N/A
	Expected Return on Plan Assets	7.00%		7.00%		7.00%		7.00%		7.00%		5.10%
Schedule of Health Care Cost Trend Rates	'
	The assumed health care cost trend rates follow:
		December 31,
		2013		2012
	Health Care Cost Trend Rate Assumed for Next Year	6.70%		6.90%
	Ultimate Health Care Cost Trend Rate Assumed	4.50%		4.50%
	Year that the Rate Reaches the Ultimate Trend Rate	2027		2027
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	'
	Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2013, amounts:
		One-Percentage-				One-Percentage-
		Point Increase				Point Decrease
		Millions of Dollars
	Effect on Total Service and Interest Cost Components	$	1			$	(1	)
	Effect on Retiree Benefit Obligation	6				(5		)
Schedule of Allocation of Plan Assets	'
	The current target allocation percentages for the major asset categories of the plan as of December 31, 2013 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.
		TEP Plan		UNS Electric and UNS Gas Plan		VEBA Trust
	Fixed Income	41%		42%		38%
	United States Large Cap	24%		24%		39%
	Non-United States Developed	15%		14%		7%
	Real Estate	8%		10%		—%
	United States Small Cap	5%		5%		5%
	Non-United States Emerging	5%		5%		9%
	Private Equity	2%		—%		—%
	Cash/Treasury Bills	—%		—%		2%
	Total	100%		100%		100%
	We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows:
		TEP Plan Assets						UNS Electric and UNS Gas Plan
								Assets
		2013			2012			2013			2012
	Asset Category
	Equity Securities	50	%		50	%		50	%		56	%
	Fixed Income Securities	40			41	%		40			33
	Real Estate	7			7	%		10			11
	Other	3			2	%		—			—
	Total	100	%		100	%		100	%		100	%
FV Measurements of Pension Plan Assets by FV Hierarchy	'
	The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:
		Fair Value Measurements of Pension Assets
		December 31, 2013
		Quoted Prices				Significant Other				Significant			Total
		in Active				Observable				Unobservable
		Markets				Inputs				Inputs
		(Level 1)				(Level 2)				(Level 3)
		Millions of Dollars
	Asset Category
	Cash Equivalents	$	1			$	—			$	—		$	1
	Equity Securities:
	United States Large Cap	—				80				—			80
	United States Small Cap	—				17				—			17
	Non-United States	—				65				—			65
	Fixed Income	—				130				—			130
	Real Estate	—				9				14			23
	Private Equity	—				—				7			7
	Total	$	1			$	301			$	21		$	323
		Fair Value Measurements of Pension Assets
		December 31, 2012
		Level 1				Level 2				Level 3			Total
		Millions of Dollars
	Asset Category
	Cash Equivalents	$	1			$	—			$	—		$	1
	Equity Securities:
	United States Large Cap	—				71				—			71
	United States Small Cap	—				15				—			15
	Non-United States	—				59				—			59
	Fixed Income	—				116				—			116
	Real Estate	—				8				13			21
	Private Equity	—				—				6			6
	Total	$	1			$	269			$	19		$	289
	Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
	Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
	Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 85% of real estate assets tracked by the index in 2013 and comprising 87% in 2012.
	Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
	The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UNS Electric and UNS Gas pension plan of $16 million at December 31, 2013 and $14 million at December 31, 2012.
	The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
Schedule of Changes in Fair Value of Plan Assets	'
	The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
		Year Ended
		December 31, 2013
		Private				Real Estate				Total
		Equity
		Millions of Dollars
	Beginning Balance at January 1, 2013	$	6			$	13			$	19
	Actual Return on Plan Assets:
	Assets Held at Reporting Date	1				1				2
	Purchases, Sales, and Settlements	—				—				—
	Ending Balance at December 31, 2013	$	7			$	14			$	21
		Year Ended
		December 31, 2012
		Private				Real Estate				Total
		Equity
		Millions of Dollars
	Beginning Balance at January 1, 2012	$	4			$	11			$	15
	Actual Return on Plan Assets:
	Assets Held at Reporting Date	1				2				3
	Purchases, Sales, and Settlements	1				—				1
	Ending Balance at December 31, 2012	$	6			$	13			$	19
Schedule of Expected Benefit Payments	'
	ESTIMATED FUTURE BENEFIT PAYMENTS
	TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate.
		2014				2015				2016			2017			2018			2019-2023
		Millions of Dollars
	Pension Benefits	$	15			$	16			$	17		$	18		$	20		$	114
	Other Retiree Benefits	5				5				5			5			5			29
	One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million.
	UNS Electric and UNS Gas expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $7 million in 2014 through 2018, and $9 million in 2019 through 2023

SHAREBASED_COMPENSATION_PLANS_

SHARE-BASED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Share-based Compensation, Stock Options, Activity	'
	See summary of stock option activity in the table below:
			2013						2012							2011
	Stock Options		Shares		Weighted				Shares			Weighted				Shares			Weighted
			(000s)		Average				(000s)			Average				(000s)			Average
					Exercise							Exercise							Exercise
					Price							Price							Price
	Outstanding, Beginning of Year		409		$	29.09			581			$	29.11			921			$	27.96
	Exercised		(127	)	30.12				(132	)		26.54				(319	)		25.6
	Forfeited/Expired		—		—				(40	)		37.88				(21	)		31.92
	Outstanding, End of Year		282		28.63				409			29.09				581			29.11
	Exercisable, End of Year		282		$	28.63			409			$	29.09			508			$	29.53
	Aggregate Intrinsic Value of Options Exercised ($000s)				$	2,897						$	1,878						$	3,690
	See summary of stock options in the tables below:
		31-Dec-13
	Aggregate Intrinsic Value for Options Outstanding ($000s)	$	8,795
	Aggregate Intrinsic Value for Options Exercisable ($000s)	$	8,795
	Weighted Average Remaining Contractual Term of Outstanding Options	4.1 years
	Weighted Average Remaining Contractual Term of Exercisable Options	4.1 years
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range	'
			Options Outstanding								Options Exercisable
	Range of Exercise Prices		Number  of		Weighted		Weighted				Number  of			Weighted
			Shares		Average		Average				Shares			Average
			(000s)		Remaining		Exercise				(000s)			Exercise Price
					Contractual		Price
					Term
	$26.11—$37.88		282		4.1 years		$	28.63			282			$	28.63
Schedule of Share-based Compensation, Restricted Stock Units Award Activity	'
	See summary of restricted stock units awarded in the table below:
			Non-Employee Directors						Management Employees
	Award Year		Restricted Stock Units		Grant Date Fair Value				Restricted Stock Units			Grant Date Fair Value
	2013		8,870		$	48.99			21,560			$	46.23
	2012		15,303		35.94				—			—
	2011		14,655		37.53				—			—
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	'
	See summary of performance shares awarded in the table below:
					Grant Date Fair Value
	Award Year		Performance Shares		TSR-Based Award				CNI-Based Award
	2013		43,120		$	45.54			$	46.23
	2012		80,140		32.71				36.4
	2011		80,440		33.73				36.58
Schedule of Nonvested Share Activity	'
	See summary of restricted stock units and performance shares current year activity in the table below:
			Restricted Stock Units						Performance Shares
			Shares		Weighted				Shares			Weighted
			(000s)		Average				(000s)			Average
					Grant  Date							Grant  Date
					Fair Value							Fair Value
	Non-vested, Beginning of Year		15		$	35.94			145			$	34.83
	Granted		31		47.04				52			44.94
	Vested		(16	)	36.27				(52	)		35.35
	Forfeited		(2	)	46.23				(32	)		37.57
	Non-vested, End of Year		28		47.12				113			38.45
Schedule of Fair Value of Vested Restricted Stock Units and Performance Shares	'
	The total fair value of restricted stock units and performance shares vested were as follows:
		Restricted Stock Units											Performance Shares
		2013			2012				2011				2013				2012				2011
		Thousands of Dollars
	Total Fair Value of Shares Vested	$	574		$	550			$	495			$	2,387			$	2,377			$	1,069

UNS_ENERGY_EARNINGS_PER_SHARE_

UNS ENERGY EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 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:
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	Numerator:
	Net Income	$	127,478		$	90,919		$	109,975
	Income from Assumed Conversion of Convertible Senior Notes (1)	—			1,100			4,390
	Adjusted Net Income Available for Diluted Common Stock Outstanding	$	127,478		$	92,019		$	114,365
		Thousands of Shares
	Denominator:
	Weighted Average Shares of Common Stock Outstanding:
	Common Shares Issued	41,446			40,212			36,780
	Fully Vested Deferred Stock Units	172			150			129
	Participating Securities	—			—			53
	Total Weighted Average Common Stock Outstanding and Participating Securities—Basic	41,618			40,362			36,962
	Effect of Dilutive Securities:
	Convertible Senior Notes (1)	—			1,062			4,281
	Options and Stock Issuable Under Share-Based Compensation Plans	357			331			366
	Total Weighted Average Common Stock Outstanding —Diluted	41,975			41,755			41,609
	-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:
		Years Ended December 31,
		2013		2012			2011
		Thousands of Shares
	Stock Options	—		50			153
	Restricted Stock Units	6		—			—
	Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6		50			153

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Cash Flow, Supplemental Disclosures	'
	A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:
		UNS Energy
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	Net Income	$	127,478		$	90,919		$	109,975
	Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
	Depreciation Expense	149,615			141,303			133,832
	Amortization Expense	27,557			35,784			30,983
	Depreciation and Amortization Recorded to Fuel and O&M Expense	7,288			6,622			6,140
	Amortization of Deferred Debt-Related Costs included in Interest Expense	3,050			3,000			3,985
	Provision for Retail Customer Bad Debts	2,263			2,767			2,072
	Use of Renewable Energy Credits for Compliance	17,706			5,935			5,695
	Deferred Income Taxes	83,501			60,264			75,515
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—			—
	Pension and Retiree Expense	22,783			21,856			21,202
	Pension and Retiree Funding	(29,161		)	(29,058		)	(28,775		)
	Share-Based Compensation Expense	3,399			2,573			2,599
	Allowance for Equity Funds Used During Construction	(6,190		)	(3,464		)	(4,496		)
	Increase (Decrease) to Reflect PPFAC/PGA Recovery	(16,313		)	32,246			(4,932		)
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
	Competition Transition Charge Revenue Refunded	—			—			(35,958		)
	Partial Write-off of Tucson to Nogales Transmission Line	—			4,668			—
	Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
	Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
	Accounts Receivable	(6,338		)	3,369			2,743
	Materials and Fuel Inventory	16,197			(39,429		)	(20,864		)
	Accounts Payable	3,223			595			8,792
	Income Taxes	(15,868		)	(11,557		)	(2,739		)
	Interest Accrued	4,875			6,922			14,344
	Taxes Other Than Income Taxes	1,941			(58		)	2,857
	Current Regulatory Liabilities	11,124			(684		)	2,644
	Other	20,421			11,486			19,097
	Net Cash Flows – Operating Activities	$	420,512		$	348,109		$	337,320
		TEP
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	Net Income	$	101,342		$	65,470		$	85,334
	Adjustments to Reconcile Net Income
	To Net Cash Flows from Operating Activities
	Depreciation Expense	118,076			110,931			104,894
	Amortization Expense	31,294			39,493			34,650
	Depreciation and Amortization Recorded to Fuel and O&M Expense	6,219			5,384			4,509
	Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,452			2,227			2,378
	Provision for Retail Customer Bad Debts	1,678			1,871			1,447
	Use of RECs for Compliance	15,990			5,071			5,190
	Deferred Income Taxes	69,950			45,232			59,309
	Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—			—
	Pension and Retiree Expense	19,878			19,289			18,816
	Pension and Retiree Funding	(27,636		)	(25,899		)	(25,878		)
	Share-Based Compensation Expense	2,709			2,029			2,027
	Allowance for Equity Funds Used During Construction	(4,526		)	(2,840		)	(3,842		)
	Increase (Decrease) to Reflect PPFAC Recovery	(12,458		)	31,113			(6,165		)
	PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
	Competition Transition Charge Revenue Refunded	—			—			(35,958		)
	Partial Write-off of Tucson to Nogales Transmission Line	—			4,484			—
	Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
	Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
	Changes in Assets and Liabilities which Provided (Used)
	Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,041		)	(871		)	4,809
Materials and Fuel Inventory	16,145			(38,384		)	(19,789		)
Accounts Payable	334			1,115			14,561
Income Taxes	(10,790		)	(11,421		)	(5,582		)
Interest Accrued	4,859			8,055			14,268
Taxes Other Than Income Taxes	1,425			905			2,282
Current Regulatory Liabilities	3,331			(3,040		)	303
Other	19,711			5,655			18,122
Net Cash Flows – Operating Activities	$	346,191		$	267,919		$	268,294
Supplemental Noncash Investing And Financing Activities Table	'
	Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
		Years Ended December 31,
		2013			2012			2011
		Thousands of Dollars
	(Decrease)/Increase to Utility Plant Accruals(1)	$	4,995		$	4,813		$	(2,741	)
	Net Cost of Removal of Interim Retirements(2)	25,182			35,983			31,626
	Capital Lease Obligations(3)	9,039			11,967			15,162
	Asset Retirement Obligations(4)	8,064			789			7,638
	(1)	The non-cash additions to Utility Plant represent accruals for capital expenditures.
	(2)	The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.
	(3)	The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.
	(4)	The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

FAIR_VALUE_MEASUREMENTS_DERIVA1

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Fair Value Measurements of Financial Assets and Liabilities	'
	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
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	14			$	14			$	—			$	—			$	—		$	14
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	7				—				3				4				(5		)	2
	Total Assets	45				16				25				4				(5		)	40
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(7		)		—				(2		)		(5		)		5			(2		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
	Total Liabilities	(15		)		—				(9		)		(6		)		5			(10		)
	Net Total Assets (Liabilities)	$	30			$	16			$	16			$	(2	)		$	—		$	30
		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
		31-Dec-13
		Millions of Dollars
	Assets
	Cash Equivalents(1)	$	—			$	—			$	—			$	—			$	—		$	—
	Restricted Cash(1)	2				2				—				—				—			2
	Rabbi Trust Investments(2)	22				—				22				—				—			22
	Energy Contracts - Regulatory Recovery(3)	2				—				1				1				(1		)	1
	Total Assets	26				2				23				1				(1		)	25
	Liabilities
	Energy Contracts - Regulatory Recovery(3)	(2		)		—				—				(2		)		1			(1		)
	Energy Contracts - Cash Flow Hedge(3)	(1		)		—				—				(1		)		—			(1		)
	Interest Rate Swaps(4)	(7		)		—				(7		)		—				—			(7		)
	Total Liabilities	(10		)		—				(7		)		(3		)		1			(9		)
	Net Total Assets (Liabilities)	$	16			$	2			$	16			$	(2	)		$	—		$	16
		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 or Level 3), 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.
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
		Years Ended December 31,
		2013				2012				2011				2013				2012			2011
		Millions of Dollars
	Increase (Decrease) to Regulatory Assets/Liabilities	$	(9	)		$	(21	)		$	2			$	—			$	(6	)	$	2
Derivative Volumes	'
	The volumes associated with our energy contracts were as follows:
		UNS Energy						TEP
		December 31, 2013			December 31, 2012			December 31, 2013			December 31, 2012
	Power Contracts GWh	1,583			2,228			779			820
	Gas Contracts GBtu	33,371			17,851			9,615			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
				31-Dec-13										Range of
		Valuation Approach		Assets				Liabilities				Unobservable Inputs		Unobservable Input
				Millions of Dollars
	Forward Contracts(1)	Market approach		$	1			$	(4	)		Market price per MWh		$	26.54		-	$	51.75
	Option Contracts(2)	Option model		3				(2		)		Market Price per MMbtu		$	3.87		-	$	4.32
												Gas Volatility		25.05		%	-	35.07		%
	Level 3 Energy Contracts			$	4			$	(6	)
	(1)	TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.
	(2)	TEP comprises less than $1 million of the option contract assets.
Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities	'
	.
	The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
		UNS Energy				TEP
		Millions of Dollars
	Balances at December 31, 2012	$	(5	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(1		)		(2		)
	Settlements	4				—
	Balances at December 31, 2013	$	(2	)		$	(2	)
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)		$	(1	)
		UNS Energy				TEP
		Millions of Dollars
	Balances at December 31, 2011	$	(10	)		$	—
	Realized/Unrealized Gains/(Losses) Recorded to:
	Net Regulatory Assets/Liabilities – Derivative Instruments	(5		)		1
	Settlements	10				(1		)
	Balances at December 31, 2012	$	(5	)		$	—
	Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)		$	—
Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments	'
	The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
				31-Dec-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				25				36				23
	Liabilities:
	Long-Term Debt
	UNS Energy	Level 2		1,507				1,521				1,498				1,583
	TEP	Level 2		1,223				1,214				1,223				1,271

CHANGES_IN_ACCUMULATIVE_OTHER_

CHANGES IN ACCUMULATIVE OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)	12 Months Ended
	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	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
		Year Ended December 31, 2013
		Thousands of Dollars
	Realized Losses on Cash Flow Hedges
	Interest Rate Swaps - Debt	$	(1,377	)	$	(1,166	)	Interest Expense Long-Term Debt
	Interest Rate Swaps - Capital Leases	(2,429		)	(2,429		)	Interest Expense Capital Leases
	Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
	Tax Benefit	1,801			1,718
	Realized Losses on Cash Flow Hedges, Net of Taxes	(2,752		)	(2,624		)
	Amortization of SERP and Defined Benefit Plans
	Prior Service Costs	(1,488		)	(1,488		)	Other Expense
	Tax Benefit	572			572
	Amortization, Net of Taxes	(916		)	(916		)
	Total Reclassifications from Other Comprehensive Income for the Period	$	(3,668	)	$	(3,540	)

QUARTERLY_FINANCIAL_DATA_Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Quarterly Financial Information	'
	comparisons among quarters of a year may not represent overall trends and changes in operations.
		UNS Energy
		First			Second		Third		Fourth
		Thousands of Dollars
		(Except Per Share Amounts)
	2013
	Operating Revenue	$	332,141		$	365,217	$	437,041	$	350,161
	Operating Income	39,895			60,803		129,765		41,033
	Net Income	11,345			34,618		67,990		13,525
	Basic EPS	0.27			0.83		1.63		0.32
	Diluted EPS	0.27			0.83		1.62		0.32
	2012
	Operating Revenue	$	315,387		$	363,998	$	434,108	$	348,273
	Operating Income (1)	34,403			68,065		106,409		42,918
	Net Income	6,476			26,273		50,664		7,506
	Basic EPS	0.17			0.65		1.22		0.18
	Diluted EPS	0.17			0.64		1.21		0.18
	EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.
		TEP
		First			Second		Third		Fourth
		Thousands of Dollars
	2013
	Operating Revenue	$	247,751		$	304,263	$	371,239	$	273,437
	Operating Income	22,747			53,433		123,177		31,014
	Net Income	1,478			30,787		64,167		4,910
	2012
	Operating Revenue	$	223,978		$	299,419	$	366,910	$	271,353
	Operating Income (1)	17,898			58,211		94,079		30,299
	Net Income (Loss)	(1,461		)	21,910		44,569		452
	(1) Immaterial variances from quarterly amounts previously reported result from line item reclassifications.

NATURE_OF_OPERATIONS_AND_SUMMA3

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Detail) (USD $)	12 Months Ended			12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
				TUCSON ELECTRIC POWER COMPANY	UNS Electric	UNS Gas	Millennium Energy Holdings [Member]	Springerville Unit 1 [Member]	Springerville Common Facilities [Member]
				sqmi
Nature Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'	'	'	'	'	'	'
Percentage of TEP owned by UNS Energy	'	100.00%	'	'	'	'	'	'	'
Percentage Of Subsidiary In Companys Asset	'	'	'	83.00%	'	'	'	'	'
Retail customers	'	'	'	413,000	93,000	150,000	'	'	'
Area in which subsidiary generates transmits and distributes electricity to retail electric customers	'	'	'	1,155	'	'	'	'	'
Investments In Unregulated Businesses As Percentage Of Companys Assets	'	'	'	'	'	'	1.00%	'	'
Restricted Cash and Cash Equivalents, Noncurrent	'	$2	$7	'	'	'	'	'	'
Capitalized interest	3.30%	'	'	'	'	'	'	'	'
Equity Method Investment, Ownership Percentage	'	'	'	'	'	'	'	14.00%	7.00%

NATURE_OF_OPERATIONS_AND_SUMMA4

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Average AFUDC Rate on Regulated Construction Expenditures	7.38%	7.22%	6.72%
UNS Electric	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Average AFUDC Rate on Regulated Construction Expenditures	8.07%	7.89%	8.18%
UNS Gas	'	'	'
Long-term Contract for Purchase of Electric Power [Line Items]	'	'	'
Average AFUDC Rate on Regulated Construction Expenditures	7.89%	7.95%	8.32%

NATURE_OF_OPERATIONS_AND_SUMMA5

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY	'	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'	'
Average annual depreciation rate	3.16%	3.22%	3.14%
UNS Electric	'	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'	'
Average annual depreciation rate	3.94%	3.99%	4.02%
UNS Gas	'	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'	'
Average annual depreciation rate	2.63%	2.69%	2.84%

PENDING_MERGER_WITH_FORTIS_INC1

PENDING MERGER WITH FORTIS INC. (Details) (Fortis Inc, USD $)	Dec. 11, 2013
Fortis Inc	'
Business Acquisition [Line Items]	'
Share price	$60.25

REGULATORY_MATTERS_Rate_Order_

REGULATORY MATTERS (Rate Order) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jun. 30, 2013

Apr. 30, 2012

Jun. 30, 2013

Jun. 30, 2013

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Electric

UNS Gas

UNS Gas

Before July 1, 2013 [Member]

After June 30, 2013 [Member] [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Schedule of Regulatory Orders [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Base rate increase approved

'

'

'

$76,000,000

'

'

'

$3,000,000

'

$2,700,000

'

'

Original cost rate base

'

'

'

1,500,000,000

'

'

'

213,000,000

'

183,000,000

'

'

Fair value of rate base

'

'

'

2,300,000,000

'

'

'

283,000,000

'

'

'

'

Approved rate of return on equity

'

'

'

10.00%

'

'

'

9.50%

'

'

'

'

Approved long term cost of debt

'

'

'

5.18%

'

'

'

5.97%

'

'

'

'

Approved short-term cost of debt

'

'

'

1.42%

'

'

'

'

'

'

'

'

Approved weighted average cost of capital

'

'

'

7.26%

'

'

'

7.83%

'

'

'

'

Approved equity portion of capital structure

'

'

'

43.50%

'

'

'

52.60%

'

'

'

'

Approved long term debt portion of capital structure

'

'

'

56.00%

'

'

'

47.40%

'

'

'

'

Approved short-term debt portion of capital structure

'

'

'

0.50%

'

'

'

'

'

'

'

'

Approved rate of return on the fair value increment of rate base

'

'

'

0.68%

'

'

'

0.50%

'

1.00%

'

'

Fair value increment of rate base

'

'

'

800,000,000

'

'

'

70,000,000

'

70,000,000

'

'

Change in composite rate

'

'

'

'

'

'

'

'

'

'

3.32%

3.00%

Expected change in annual depreciation

'

'

'

11,000,000

'

'

'

'

'

'

'

'

PPFAC credit

'

'

'

0.1388

'

'

'

'

'

'

'

'

PPFAC Reduction - TEP Rate Order

3,000,000

0

0

3,000,000

3,000,000

0

0

'

'

'

'

'

Deferred costs related to San Juan Mine Fire

'

'

'

10,000,000

'

'

'

'

'

'

'

'

Revenue Recognized Under Lost Fixed Cost Recovery Mechanism

'

'

'

2,000,000

'

'

'

'

'

'

'

'

Environmental compliance adjustor capped rate

'

'

'

0.025

'

'

'

'

'

'

'

'

Retail revenue cap on environmental compliance adjustor

'

'

'

0.25%

'

'

'

'

'

'

'

'

Approved energy efficiency budget

'

'

'

21,000,000

'

'

'

5,000,000

2,000,000

'

'

'

Performance Incentive Included in Efficiency Budget

'

'

'

$2,000,000

'

'

'

'

'

'

'

'

Percentage increase in base rates approved by regulator

'

'

'

'

'

'

'

'

'

1.80%

'

'

Authorized rate of return

'

'

'

'

'

'

'

'

'

8.30%

'

'

REGULATORY_MATTERS_Cost_Recove

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

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Oct. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

UNS Gas

UNS Gas

UNS Gas

UNS Gas

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Electric

UNS Electric

UNS Electric

UNS Electric

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Before November 1, 2013 [Member]

From November 1, 2013 through April 30, 2014 [Member]

UNS Gas

UNS Gas

UNS Gas

UNS Gas

Schedule of Regulatory Cost Recovery Mechanisms [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) of PPFAC

'

'

'

'

'

'

'

'

'

'

'

0.83

'

'

'

'

'

Deferral balance

'

'

'

'

'

'

'

'

'

$10

'

$10

'

'

'

'

'

PPFAC balance over-collected

'

'

'

'

'

'

'

'

'

14

'

14

'

'

'

'

'

Factor automatically adjusts restricted from rising or falling in twelve month period

'

0.15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gas Is Required To Request Approval Of Surcredit When Pga Bank Balance Exceeds

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchased Gas Adjustor Credit

'

'

0.045

0.1

'

'

'

'

'

'

'

'

'

'

'

'

'

Customer refund liability, current

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchased gas adjustor rate

'

'

'

'

'

'

'

'

'

'

'

'

'

0.4504

0.5202

0.528

0.6501

Approved Investment Cost By ACC To Invest In Owned Solar Projects

'

'

'

'

40

'

'

'

'

'

7

'

'

'

'

'

'

Proposed Collections From Customers For Renewable Energy Programs

'

'

'

'

34

'

'

'

'

'

6

'

'

'

'

'

'

Amount receivable as return on investment

'

'

'

'

'

'

2

2

1

'

'

0.5

0.5

'

'

'

'

Approved energy efficiency budget

$2

'

'

'

'

$21

'

'

'

$5

'

'

'

'

'

'

'

Retail revenue cap on environmental compliance adjustor

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

Cap on increase in lost fixed cost recovery rate

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

REGULATORY_MATTERS_Summary_of_

REGULATORY MATTERS (Summary of PPFAC Rates) (Detail)

3 Months Ended

6 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

3 Months Ended

4 Months Ended

5 Months Ended

7 Months Ended

Mar. 31, 2012

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Mar. 31, 2012

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Mar. 31, 2012

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Aug. 31, 2013

Dec. 31, 2013

31-May-13

31-May-12

Dec. 31, 2012

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

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Electric

UNS Electric

UNS Electric

UNS Electric

UNS Electric

PPFAC [Member]

PPFAC [Member]

PPFAC [Member]

PPFAC [Member]

CTC [Member]

CTC [Member]

CTC [Member]

CTC [Member]

Schedule of Regulatory Matters Summary Of PPFAC Rates [Table] [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PPFAC Rates

0

0.0014

0.0077

0.0077

0.0053

0.0014

0.0077

0.0077

-0.0053

[1]

0

[1]

0

[1]

0

[1]

-0.0092

-0.004

-0.0144

-0.0088

-0.0144

[1]

TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.

REGULATORY_MATTERS_Regulatory_

REGULATORY MATTERS (Regulatory Assets and Liabilities) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Regulatory Assets And Liabilities [Line Items]	'		'
Regulatory Assets—Current	$52,763		$51,619
Regulatory Assets—Noncurrent	150,584		191,077
Regulatory Liabilities - Current	-53,935		-43,516
Regulatory Liability, Noncurrent	-302,482		-279,111
UNS Energy	'		'
Regulatory Assets And Liabilities [Line Items]	'		'
Property Tax Deferrals Current	20,000	[1]	18,000	[1]
Derivative Instruments Regulatory Assets Current	1,000		11,000
Mine Fire Cost Deferral	10,000	[2]	'
PPFAC	14,000	[2]	15,000	[2]
DSM and LFCR Regulatory Assets Current	3,000	[2]	'
DSM	'		5,000	[2]
Other Current Regulatory Assets	5,000	[3]	3,000	[3]
Regulatory Assets—Current	53,000		52,000
Pension And Other Postretirement Benefits Noncurrent	80,000		139,000
Income Taxes Recoverable through Future Revenues	25,000	[4]	10,000	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	25,000	[5]	22,000	[5]
Tucson to Nogales Transmission Line	5,000	[6]	5,000	[6]
Other Regulatory Assets Noncurrent	16,000	[3]	15,000	[3]
Regulatory Assets—Noncurrent	151,000		191,000
PGA	-15,000		-17,000
RES	-31,000		-23,000
Other Current Regulatory Liabilities Current	-8,000		-4,000
Regulatory Liabilities - Current	-54,000		-44,000
Net Cost of Removal for Interim Retirements	-292,000	[7]	-267,000	[7]
Income Taxes Payable through Future Rates	-6,000		-6,000
Deferred Investment Tax Credit	-4,000	[8]	-5,000	[8]
Other Regulatory Liabilities	'		1,000
Regulatory Liability, Noncurrent	-302,000		-279,000
Total Net Regulatory Assets (Liabilities)	-152,000		-80,000
TUCSON ELECTRIC POWER COMPANY	'		'
Regulatory Assets And Liabilities [Line Items]	'		'
Property Tax Deferrals Current	20,000	[1]	18,000	[1]
Derivative Instruments Regulatory Assets Current	1,000		2,000
Mine Fire Cost Deferral	10,000	[2]	'
PPFAC	4,000	[2]	7,000	[2]
DSM and LFCR Regulatory Assets Current	3,000	[2]	'
DSM	'		5,000	[2]
Other Current Regulatory Assets	5,000	[3]	2,000	[3]
Regulatory Assets—Current	42,555		34,345
Pension And Other Postretirement Benefits Noncurrent	75,000		130,000
Income Taxes Recoverable through Future Revenues	22,000	[4]	8,000	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	25,000	[5]	22,000	[5]
Tucson to Nogales Transmission Line	5,000	[6]	5,000	[6]
Other Regulatory Assets Noncurrent	14,000	[3]	13,000	[3]
Regulatory Assets—Noncurrent	141,030		178,330
PGA	0		0
RES	-22,000		-19,000
Other Current Regulatory Liabilities Current	-2,000		-2,000
Regulatory Liabilities - Current	-23,701		-20,822
Net Cost of Removal for Interim Retirements	-254,000	[7]	-231,000	[7]
Income Taxes Payable through Future Rates	-5,000		-5,000
Deferred Investment Tax Credit	-4,000	[8]	-5,000	[8]
Other Regulatory Liabilities	'		0
Regulatory Liability, Noncurrent	-263,270		-241,189
Total Net Regulatory Assets (Liabilities)	-103,386		-50,000
UNS Electric	'		'
Regulatory Assets And Liabilities [Line Items]	'		'
Property Tax Deferrals Current	0	[1]	0	[1]
Derivative Instruments Regulatory Assets Current	0		6,000
Mine Fire Cost Deferral	0	[2]	'
PPFAC	10,000	[2]	8,000	[2]
DSM and LFCR Regulatory Assets Current	0	[2]	'
DSM	'		0	[2]
Other Current Regulatory Assets	0	[3]	0	[3]
Regulatory Assets—Current	10,000		14,000
Pension And Other Postretirement Benefits Noncurrent	3,000		5,000
Income Taxes Recoverable through Future Revenues	3,000	[4]	2,000	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	0	[5]	0	[5]
Tucson to Nogales Transmission Line	0	[6]	0	[6]
Other Regulatory Assets Noncurrent	2,000	[3]	1,000	[3]
Regulatory Assets—Noncurrent	8,000		8,000
PGA	0		0
RES	-9,000		-4,000
Other Current Regulatory Liabilities Current	-6,000		-1,000
Regulatory Liabilities - Current	-15,000		-5,000
Net Cost of Removal for Interim Retirements	-12,000	[7]	-11,000	[7]
Income Taxes Payable through Future Rates	0		0
Deferred Investment Tax Credit	0	[8]	0	[8]
Other Regulatory Liabilities	'		1,000
Regulatory Liability, Noncurrent	-12,000		-12,000
Total Net Regulatory Assets (Liabilities)	-9,000		5,000
UNS Gas	'		'
Regulatory Assets And Liabilities [Line Items]	'		'
Property Tax Deferrals Current	0	[1]	0	[1]
Derivative Instruments Regulatory Assets Current	0		3,000
Mine Fire Cost Deferral	0	[2]	'
PPFAC	0	[2]	0	[2]
DSM and LFCR Regulatory Assets Current	0	[2]	'
DSM	'		0	[2]
Other Current Regulatory Assets	0	[3]	1,000	[3]
Regulatory Assets—Current	0		4,000
Pension And Other Postretirement Benefits Noncurrent	2,000		4,000
Income Taxes Recoverable through Future Revenues	0	[4]	0	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	0	[5]	0	[5]
Tucson to Nogales Transmission Line	0	[6]	0	[6]
Other Regulatory Assets Noncurrent	0	[3]	1,000	[3]
Regulatory Assets—Noncurrent	2,000		5,000
PGA	-15,000		-17,000
RES	0		0
Other Current Regulatory Liabilities Current	0		-1,000
Regulatory Liabilities - Current	-15,000		-18,000
Net Cost of Removal for Interim Retirements	-26,000	[7]	-25,000	[7]
Income Taxes Payable through Future Rates	-1,000		-1,000
Deferred Investment Tax Credit	0	[8]	0	[8]
Other Regulatory Liabilities	'		0
Regulatory Liability, Noncurrent	-27,000		-26,000
Total Net Regulatory Assets (Liabilities)	($40,000)		($35,000)
[1]	Property Tax is recovered over approximately a six-month period as costs are paid, rather than as costs are accrued.
[2]	See Cost Recovery Mechanisms discussion above.
[3]	TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).
[4]	Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.
[5]	Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
[6]	TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.
[7]	Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.
[8]	The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

REGULATORY_MATTERS_Regulatory_1

REGULATORY MATTERS (Regulatory Assets and Liabilities Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013
Regulatory Assets [Line Items]	'
Property Tax Recovery Period	'6 months
TUCSON ELECTRIC POWER COMPANY	'
Regulatory Assets [Line Items]	'
Recovery Period Of Reacquired Debt	'2032
Recovery Period Of Coal Contract Amendment	'2017
Recovery Period for Rate Case Costs	'3 years
Recovery Other Assets	'2014
Minimum [Member] | TUCSON ELECTRIC POWER COMPANY	'
Regulatory Assets [Line Items]	'
Expected Life Of Mines	'14 years
Maximum [Member] | TUCSON ELECTRIC POWER COMPANY	'
Regulatory Assets [Line Items]	'
Expected Life Of Mines	'20 years

BUSINESS_SEGMENTS_Reporting_De

BUSINESS SEGMENTS (Reporting) (Details)	12 Months Ended
	Dec. 31, 2013
	Segment
Segment Reporting [Abstract]	'
Number of Reportable Segments	3

BUSINESS_SEGMENTS_Reconciliati

BUSINESS SEGMENTS (Reconciliation of Income Statement Items from Segments to Consolidation) (Detail) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting, Revenue Reconciling Item [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

$350,161

$437,041

$365,217

$332,141

$348,273

$434,108

$363,998

$315,387

$1,484,560

$1,461,766

$1,478,702

Operating Revenues-Intersegment

'

'

'

'

'

'

'

'

0

[1]

0

[1]

0

[1]

Depreciation and Amortization

'

'

'

'

'

'

'

'

177,172

177,087

164,815

Interest Income

'

'

'

'

'

'

'

'

534

1,106

4,568

Interest Expense

'

'

'

'

'

'

'

'

93,375

105,352

112,358

Income Tax Expense

'

'

'

'

'

'

'

'

58,427

55,727

66,951

Net Income

13,525

67,990

34,618

11,345

7,506

50,664

26,273

6,476

127,478

90,919

109,975

Capital Expenditures

'

'

'

'

'

'

'

'

-325,886

-307,277

-374,122

Assets

4,273,069

'

'

'

4,140,429

'

'

'

4,273,069

4,140,429

'

Reconciling Adjustments [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting, Revenue Reconciling Item [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

-2,000

-1,000

1,000

Operating Revenues-Intersegment

'

'

'

'

'

'

'

'

-39,000

[1]

-40,000

[1]

-42,000

[1]

Depreciation and Amortization

'

'

'

'

'

'

'

'

0

0

-1,000

Interest Income

'

'

'

'

'

'

'

'

0

0

0

Interest Expense

'

'

'

'

'

'

'

'

0

0

0

Income Tax Expense

'

'

'

'

'

'

'

'

0

0

-2,000

Net Income

'

'

'

'

'

'

'

'

0

0

-3,000

Capital Expenditures

'

'

'

'

'

'

'

'

0

0

121,000

Assets

-1,192,000

'

'

'

-1,122,000

'

'

'

-1,192,000

-1,122,000

'

TUCSON ELECTRIC POWER COMPANY | Operating Segments [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting, Revenue Reconciling Item [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

1,180,000

1,145,000

1,141,000

Operating Revenues-Intersegment

'

'

'

'

'

'

'

'

17,000

[1]

17,000

[1]

15,000

[1]

Depreciation and Amortization

'

'

'

'

'

'

'

'

149,000

150,000

140,000

Interest Income

'

'

'

'

'

'

'

'

0

0

4,000

Interest Expense

'

'

'

'

'

'

'

'

79,000

88,000

89,000

Income Tax Expense

'

'

'

'

'

'

'

'

48,000

39,000

52,000

Net Income

'

'

'

'

'

'

'

'

101,000

65,000

85,000

Capital Expenditures

'

'

'

'

'

'

'

'

-253,000

-253,000

-352,000

Assets

3,556,000

'

'

'

3,461,000

'

'

'

3,556,000

3,461,000

'

UNS Electric | Operating Segments [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting, Revenue Reconciling Item [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

174,000

189,000

188,000

Operating Revenues-Intersegment

'

'

'

'

'

'

'

'

2,000

[1]

1,000

[1]

2,000

[1]

Depreciation and Amortization

'

'

'

'

'

'

'

'

19,000

18,000

17,000

Interest Income

'

'

'

'

'

'

'

'

1,000

0

0

Interest Expense

'

'

'

'

'

'

'

'

7,000

8,000

7,000

Income Tax Expense

'

'

'

'

'

'

'

'

7,000

11,000

11,000

Net Income

'

'

'

'

'

'

'

'

12,000

17,000

18,000

Capital Expenditures

'

'

'

'

'

'

'

'

-56,000

-38,000

-96,000

Assets

404,000

'

'

'

370,000

'

'

'

404,000

370,000

'

UNS Gas | Operating Segments [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting, Revenue Reconciling Item [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

131,000

129,000

149,000

Operating Revenues-Intersegment

'

'

'

'

'

'

'

'

3,000

[1]

4,000

[1]

2,000

[1]

Depreciation and Amortization

'

'

'

'

'

'

'

'

9,000

9,000

8,000

Interest Income

'

'

'

'

'

'

'

'

0

0

0

Interest Expense

'

'

'

'

'

'

'

'

6,000

6,000

7,000

Income Tax Expense

'

'

'

'

'

'

'

'

7,000

6,000

7,000

Net Income

'

'

'

'

'

'

'

'

11,000

9,000

10,000

Capital Expenditures

'

'

'

'

'

'

'

'

-17,000

-16,000

-13,000

Assets

311,000

'

'

'

310,000

'

'

'

311,000

310,000

'

Other | Operating Segments [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting, Revenue Reconciling Item [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

2,000

[2]

0

[2]

0

[2]

Operating Revenues-Intersegment

'

'

'

'

'

'

'

'

17,000

[1],[2]

18,000

[1],[2]

23,000

[1],[2]

Depreciation and Amortization

'

'

'

'

'

'

'

'

0

[2]

0

[2]

1,000

[2]

Interest Income

'

'

'

'

'

'

'

'

0

[2]

1,000

[2]

1,000

[2]

Interest Expense

'

'

'

'

'

'

'

'

1,000

[2]

3,000

[2]

9,000

[2]

Income Tax Expense

'

'

'

'

'

'

'

'

-4,000

[2]

0

[2]

-1,000

[2]

Net Income

'

'

'

'

'

'

'

'

3,000

[2]

0

[2]

0

[2]

Capital Expenditures

'

'

'

'

'

'

'

'

0

[2]

0

[2]

-34,000

[2]

Assets

$1,194,000

[2]

'

'

'

$1,121,000

[2]

'

'

'

$1,194,000

[2]

$1,121,000

[2]

'

[1]

Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

[2]

Other includes the UNS Energy and UES holding companies, Millennium, and UED.

UTILITY_PLANT_AND_JOINTLYOWNED2

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Plant in Service:	'		'
Total Plant in Service	$5,192,122,000		$5,005,768,000
Utility Plant under Capital Leases	638,000,000	[1]	583,000,000	[1]
Electricity Generation Plant, Non-Nuclear [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	1,974,000,000		1,932,000,000
Electric Transmission Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	912,000,000		842,000,000
Electric Distribution Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	1,529,000,000		1,495,000,000
Gas Distribution Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	252,000,000		240,000,000
Gas Transmission Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	18,000,000		18,000,000
General Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	356,000,000		347,000,000
Software Costs [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	142,000,000	[2],[3]	124,000,000	[2],[3]
Intangible Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	5,000,000		5,000,000
Electric Plant Held for Future Use [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	4,000,000		3,000,000
TUCSON ELECTRIC POWER COMPANY	'		'
Plant in Service:	'		'
Total Plant in Service	4,467,667,000		4,348,041,000
Utility Plant under Capital Leases	638,000,000	[1]	583,000,000	[1]
TUCSON ELECTRIC POWER COMPANY | Electricity Generation Plant, Non-Nuclear [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	1,889,000,000		1,847,000,000
TUCSON ELECTRIC POWER COMPANY | Electric Transmission Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	825,000,000		796,000,000
TUCSON ELECTRIC POWER COMPANY | Electric Distribution Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	1,298,000,000		1,271,000,000
TUCSON ELECTRIC POWER COMPANY | Gas Distribution Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	0		0
TUCSON ELECTRIC POWER COMPANY | Gas Transmission Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	0		0
TUCSON ELECTRIC POWER COMPANY | General Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	312,000,000		309,000,000
TUCSON ELECTRIC POWER COMPANY | Software Costs [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	141,000,000	[2],[3]	123,000,000	[2],[3]
TUCSON ELECTRIC POWER COMPANY | Intangible Plant [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	0		0
TUCSON ELECTRIC POWER COMPANY | Electric Plant Held for Future Use [Member]	'		'
Plant in Service:	'		'
Total Plant in Service	$3,000,000		$2,000,000
[1]	In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.
[2]	Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.
[3]	The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.

UTILITY_PLANT_AND_JOINTLYOWNED3

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]	'	'	'
Capitalized Computer Software, Gross	$40	$36	'
Amortization of computer software costs	14	13	10
TUCSON ELECTRIC POWER COMPANY	'	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'	'
Capitalized Computer Software, Gross	39	35	'
Amortization of computer software costs	$14	$13	$10

UTILITY_PLANT_AND_JOINTLYOWNED4

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for TEP's Generation-Related Capital Leases) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest Expense - Included in:	'	'	'
Interest Expense	$25,140,000	$33,613,000	$40,358,000
Total Lease Expense	47,000,000	55,000,000	62,000,000
Operating Expenses - Fuel	'	'	'
Interest Expense - Included in:	'	'	'
Interest Expense	2,000,000	3,000,000	4,000,000
Amortization of Capital Lease Assets	5,000,000	4,000,000	3,000,000
Other Expense [Member]	'	'	'
Interest Expense - Included in:	'	'	'
Interest Expense	0	0	1,000,000
Operating Expenses - Amortization [Member]	'	'	'
Interest Expense - Included in:	'	'	'
Amortization of Capital Lease Assets	$15,000,000	$14,000,000	$14,000,000

UTILITY_PLANT_AND_JOINTLYOWNED5

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service) (Detail)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Generation Plant	'22 years		'	'
Transmission Plant	'32 years		'	'
Distribution Plant	'35 years		'	'
General Plant	'11 years		'	'
Depreciation Rate	3.16%		3.22%	3.14%
TUCSON ELECTRIC POWER COMPANY | Electric Generation Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	3.31%	[1]	'	'
TUCSON ELECTRIC POWER COMPANY | Electric Transmission Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	1.48%	[2]	'	'
TUCSON ELECTRIC POWER COMPANY | Electric Distribution Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	2.08%	[1]	'	'
TUCSON ELECTRIC POWER COMPANY | General Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	5.48%	[3]	'	'
UNS Electric	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Generation Plant	'36 years		'	'
Transmission Plant	'19 years		'	'
Distribution Plant	'15 years		'	'
General Plant	'7 years		'	'
Depreciation Rate	3.94%		3.99%	4.02%
UNS Electric | Electric Generation Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	2.56%	[2]	'	'
UNS Electric | Electric Transmission Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	3.36%	[2]	'	'
UNS Electric | Electric Distribution Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	3.97%	[2]	'	'
UNS Electric | General Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	8.01%	[2]	'	'
UNS Gas	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Generation Plant	'41 years		'	'
Transmission Plant	'54 years		'	'
General Plant	'7 years		'	'
Depreciation Rate	2.63%		2.69%	2.84%
UNS Gas | Electric Generation Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	2.37%	[2]	'	'
UNS Gas | Gas Transmission Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	1.54%	[2]	'	'
UNS Gas | General Plant [Member]	'		'	'
Public Utility, Property, Plant and Equipment [Line Items]	'		'	'
Depreciation Rate	4.38%	[2]	'	'
[1]	In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.
[2]	The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.
[3]	Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.

UTILITY_PLANT_AND_JOINTLYOWNED6

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013
Minimum [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'23 years
Minimum [Member] | Computer Software, Intangible Asset [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'3 years
Minimum [Member] | Application Software [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'5 years
Minimum [Member] | Other Intangible Assets [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'15 years
Maximum [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'35 years
Maximum [Member] | Computer Software, Intangible Asset [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'5 years
Maximum [Member] | Application Software [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'19 years
Maximum [Member] | Other Intangible Assets [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'25 years

UTILITY_PLANT_AND_JOINTLYOWNED7

UTILITY PLANT AND JOINTLY-OWNED FACILITES (TEP's Interests in Jointly-Owned Generating Stations and Transmission Systems) (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Public Utility, Property, Plant and Equipment [Line Items]	'
Plant in Service	$1,084
Construction Work in Progress	52
Accumulated Depreciation	607
Net Book Value	529
San Juan Units 1 and 2 [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Percentage of ownership in generating station	50.00%
Plant in Service	448
Construction Work in Progress	6
Accumulated Depreciation	230
Net Book Value	224
Navajo Units 1, 2, and 3 [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Percentage of ownership in generating station	7.50%
Plant in Service	152
Construction Work in Progress	1
Accumulated Depreciation	110
Net Book Value	43
Four Corners Units 4 and 5 [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Percentage of ownership in generating station	7.00%
Plant in Service	101
Construction Work in Progress	2
Accumulated Depreciation	75
Net Book Value	28
Luna Energy Facility [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Percentage of ownership in generating station	33.30%
Plant in Service	53
Construction Work in Progress	0
Accumulated Depreciation	2
Net Book Value	51
Transmission Facilities [Member]	'
Public Utility, Property, Plant and Equipment [Line Items]	'
Plant in Service	330
Construction Work in Progress	43
Accumulated Depreciation	190
Net Book Value	$183

UTILITY_PLANT_AND_JOINTLYOWNED8

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Asset Retirement Obligations) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]	'		'		'
Liabilities Incurred	$8,064,000	[1]	$789,000	[1]	$7,638,000	[1]
UNS Energy	'		'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'		'
Beginning Balance	14,000,000		13,000,000		'
Liabilities Incurred	1,000,000		0		'
Accretion Expense	1,000,000		1,000,000		'
Revision to Estimated Cash Flows	7,000,000	[2]	0	[2]	'
Ending Balance	23,000,000		14,000,000		'
UNS Electric	'		'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'		'
Ending Balance	$1,000,000		$1,000,000		'
[1]	The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.
[2]	Primarily related to changes in expected retirement dates of generating facilities.

DEBT_CREDIT_FACILITIES_AND_CAP2

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

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 30, 2013

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2012

Mar. 31, 2013

Sep. 30, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2010

Aug. 31, 2009

Aug. 31, 2011

Dec. 31, 2012

Dec. 31, 2005

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2012

Mar. 31, 2012

Jun. 30, 2012

Mar. 31, 2012

Oct. 31, 2013

Dec. 31, 2013

Nov. 30, 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

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS ELECTRIC, INC.

Parent [Member]

Parent [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Letter of Credit [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Collateralized Mortgage Backed Securities [Member]

Variable Rate Bonds [Member]

Variable Rate Bonds [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Springerville Common Facilities Lease Debt [Member]

Variable Rate Demand Obligation [Member]

Variable Rate Demand Obligation [Member]

Variable Rate Demand Obligation [Member]

Uns Electric Term Loan [Member]

Convertible Debt [Member]

Convertible Debt [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Parent [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

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, face amount

'

'

'

'

'

'

'

$16,000,000

$177,000,000

'

$91,000,000

$150,000,000

'

$115,000,000

$37,000,000

'

$30,000,000

'

$150,000,000

'

'

'

'

'

'

'

'

'

'

$100,000,000

Fixed interest rate of long-term debt

'

'

'

'

'

'

6.38%

4.50%

4.50%

'

4.00%

3.85%

'

'

'

'

'

'

4.50%

'

'

'

'

5.85%

5.85%

5.88%

5.88%

'

'

'

Repayments of convertible debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Amount of 1992 mortgage bonds used to secure letter of credit facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

423,000,000

'

'

Derivative amount of hedged item

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed rate of interest related to interest rate swap

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.40%

0.97%

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative basis spread

'

'

'

'

'

'

'

'

'

'

'

'

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayment of outstanding credit facility

108,000,000

381,000,000

351,000,000

78,000,000

199,000,000

210,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

72,000,000

'

'

'

'

'

'

'

'

'

'

Repayments of long-term debt

0

9,341,000

252,125,000

0

6,535,000

172,460,000

'

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt extinguishment

'

'

'

'

'

'

91,000,000

16,000,000

184,000,000

193,000,000

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued interest portion on debt repayment

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Effective interest rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.95%

'

Term of debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

Debt instrument

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate spread on LIBOR borrowing

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.13%

'

'

'

1.13%

1.25%

1.13%

'

'

'

'

'

'

'

DEBT_CREDIT_FACILITIES_AND_CAP3

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Credit agreements) (Details) (USD $)

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2013

Feb. 25, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Feb. 14, 2014

Feb. 25, 2014

Feb. 14, 2014

Dec. 31, 2013

Nov. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Feb. 14, 2014

Feb. 14, 2014

TUCSON ELECTRIC POWER COMPANY

UNS Gas and UNS Electric [Member]

Parent [Member]

Subsequent Event [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Gas and UNS Electric [Member]

Parent [Member]

Parent [Member]

UNS ELECTRIC, INC.

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS ELECTRIC, INC.

UNS ELECTRIC, INC.

Subsequent Event [Member]

Subsequent Event [Member]

Letter of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

TUCSON ELECTRIC POWER COMPANY

Parent [Member]

UNS ELECTRIC, INC.

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

TUCSON ELECTRIC POWER COMPANY

UNS ELECTRIC, INC.

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility borrowing capacity

'

$100,000,000

$125,000,000

'

$200,000,000

'

'

'

'

'

'

'

'

$186,000,000

'

'

'

'

'

Letters of credit outstanding

'

'

'

'

'

'

'

'

'

'

'

'

82,000,000

'

'

'

'

'

'

Outstanding borrowings under the company credit agreement

37,000,000

'

'

'

0

'

54,000,000

45,000,000

22,000,000

90,000,000

52,000,000

25,000,000

1,000,000

'

1,000,000

500,000

500,000

1,000,000

500,000

Average interest rate

'

'

'

'

'

'

1.70%

2.00%

'

'

'

'

'

'

'

'

'

'

'

Interest rate spread on LIBOR borrowing

'

'

'

'

1.13%

1.13%

1.25%

'

'

'

'

'

1.13%

'

'

'

'

'

'

Interest rate in addition to alternate base rate for alternate base rate loans

'

'

'

'

0.13%

0.13%

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowings outstanding limit

'

70,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letter of credit cancelled

'

'

'

'

'

'

'

'

'

'

'

'

$104,000,000

'

'

'

'

'

'

Commitment fee percentage

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

DEBT_CREDIT_FACILITIES_AND_CAP4

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (TEP Capital Lease) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 31, 2013

Dec. 31, 2013

Aug. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jan. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jan. 31, 2014

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

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Springerville Unit One Lease Debt [Member]

Springerville Unit One Lease Debt [Member]

Springerville Unit One Lease Debt [Member]

Springerville Common Facilities Lease Debt [Member]

Subsequent Event [Member]

Springerville Unit One Lease [Member]

Springerville Unit One Lease [Member]

Springerville Unit One Lease [Member]

Springerville Coal Handling Facilities Lease [Member]

Springerville Common Facilities [Member]

Springerville Common Facility Lease Part One [Member]

Springerville Common Facility Lease Part Two [Member]

Springerville Common Facilities Lease Debt [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

MW

MW

MW

lease

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Capital Lease Obligation

'

'

'

'

'

'

$55,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Long-term Capital Lease Obligations

99,621,000

89,452,000

74,381,000

99,621,000

89,452,000

74,343,000

'

'

'

'

'

'

'

'

'

'

'

'

80,000,000

Equity method investment, aggregate cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

36,000,000

36,000,000

'

'

Derivative basis spread

'

'

'

'

'

'

'

'

'

'

'

'

'

1.75%

'

'

'

1.75%

'

Lease arrangement, purchase price per kW

'

'

'

'

'

'

'

478

'

'

'

'

'

'

'

'

'

'

'

Generating capacity in jointly owned facility, in MWs

'

'

'

'

'

'

'

387

'

'

'

'

'

'

'

'

'

'

'

Percentage of interest committed to purchase

'

'

'

'

'

'

0.106

'

0.248

'

'

'

'

'

'

'

'

'

'

Generating capacity purchased, in MWs

'

'

'

'

'

'

41

192

96

'

'

'

'

'

'

'

'

'

'

Lease arrangement, fair market value purchase price

'

'

'

'

'

'

20,000,000

'

46,000,000

'

'

'

'

'

'

'

'

'

'

Percentage of interest owned after close of purchases

'

'

'

'

'

'

0.495

'

'

'

'

'

'

'

'

'

'

'

'

Increase in utility plant under capital lease

'

'

'

'

'

'

55,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Fixed price to acquire leased interest in facilities

'

'

'

'

'

'

'

'

'

120,000,000

'

38,000,000

68,000,000

'

'

'

'

'

'

Proceeds from collection of lease receivables

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$9,000,000

'

'

'

'

Lease renewal period

'

'

'

'

'

'

'

'

'

'6 years

'2 years

'

'

'

'

'

'

'

'

Additional renewal period

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

Number of operating lease

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

DEBT_CREDIT_FACILITIES_AND_CAP5

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Interest Rates on TEP's Variable Rate IDBs) (Detail) (TUCSON ELECTRIC POWER COMPANY, Variable Rate Demand Obligation [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY | Variable Rate Demand Obligation [Member]	'	'	'
Schedule of Interest Rate [Line Items]	'	'	'
Average Interest Rate	0.10%	0.17%	0.18%
Range of Average weekly interest rate, minimum	0.06%	0.06%	0.05%
Average Weekly Interest Rate Range Maximum	0.25%	0.26%	0.34%

DEBT_CREDIT_FACILITIES_AND_CAP6

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Effect of Fixing Interest Rates on Amortizing Principal Balances of Swaps) (Detail) (Springerville Common Facilities Lease Debt [Member], TUCSON ELECTRIC POWER COMPANY, USD $)	Dec. 31, 2013
Derivative Instruments And Hedging Activities [Line Items]	'
Derivative basis spread	1.75%
Interest Rate Swap One [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Derivative amount of hedged item	33,000,000
Fixed rate of interest related to interest rate swap	5.77%
Derivative basis spread	1.75%
Interest Rate Swap Two [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Derivative amount of hedged item	16,000,000
Fixed rate of interest related to interest rate swap	3.18%
Derivative basis spread	1.75%
Interest Rate Swap Three [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Derivative amount of hedged item	6,000,000
Fixed rate of interest related to interest rate swap	3.32%
Derivative basis spread	1.75%

DEBT_CREDIT_FACILITIES_AND_CAP7

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013		Dec. 31, 2013
In Thousands, unless otherwise specified			UNS Gas	UNS ELECTRIC, INC.	UNS Energy	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	Capital Lease Obligations [Member]	Long-term Debt [Member]		Variable Rate Bonds [Member]
								TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY		Unsecured Debt [Member]
											TUCSON ELECTRIC POWER COMPANY
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'	'	'	'	'	'	'	'		'
Term of debt instruments	'	'	'	'	'	'	'	'	'		'5 years
2014	$214	'	$0	$0	$0	$214	'	$214	$0	[1]	'
2015	199	'	50	80	0	69	'	69	0	[1]	'
2016	149	'	0	0	54	95	'	17	78	[1]	'
2017	18	'	0	0	0	18	'	18	0	[1]	'
2018	111	'	0	0	0	111	'	11	100	[1]	'
Total 2014 - 2018	691	'	50	80	54	507	'	329	178	[1]	'
Thereafter	1,176	'	50	50	0	1,076	'	30	1,046	[1]	'
Less: Imputed Interest	-42	'	0	0	0	-42	'	-42	0	[1]	'
Long-term Debt and Capital Lease Obligations	1,825	'	'	'	'	1,541	'	'	'		'
Total	$1,507,070	$1,498,442	$100	$130	$54	$1,223,070	$1,223,442	$317	$1,224	[1]	'
[1]	$115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

DEBT_CREDIT_FACILITIES_AND_CAP8

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Parenthetical) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	Dec. 31, 2013	Dec. 31, 2010	Dec. 31, 2013	Mar. 31, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012
	Variable Rate Demand Obligation [Member]	Variable Rate Demand Obligation [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]	'	'	'	'	'	'	'
Debt instrument, face amount	$115,000,000	$37,000,000	'	$91,000,000	$150,000,000	$16,000,000	$177,000,000
Debt discount	'	'	$1,000,000	'	'	'	'

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Commitments) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	$234
2015	163
2016	141
2017	135
2018	108
Thereafter	956
Total	1,737
Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	103
2015	83
2016	80
2017	75
2018	49
Thereafter	345
Total	735
Purchased Power [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	75
2015	17
2016	0
2017	0
2018	0
Thereafter	0
Total	92
Transmission Facilities [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	7
2015	13
2016	12
2017	12
2018	11
Thereafter	27
Total	82
Renewable Energy Power Purchase Agreement [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	36
2015	37
2016	37
2017	37
2018	37
Thereafter	485
Total	669
RES Performance Based Incentives Minimum Commitment [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	9
2015	9
2016	9
2017	9
2018	9
Thereafter	85
Total	130
Operating Lease [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	4
2015	4
2016	3
2017	2
2018	2
Thereafter	14
Total	29
TUCSON ELECTRIC POWER COMPANY	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	148
2015	116
2016	111
2017	109
2018	83
Thereafter	813
Total	1,380
TUCSON ELECTRIC POWER COMPANY | Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	77
2015	63
2016	64
2017	62
2018	36
Thereafter	285
Total	587
TUCSON ELECTRIC POWER COMPANY | Purchased Power [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	27
2015	5
2016	0
2017	0
2018	0
Thereafter	0
Total	32
TUCSON ELECTRIC POWER COMPANY | Transmission Facilities [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	3
2015	6
2016	6
2017	6
2018	6
Thereafter	21
Total	48
TUCSON ELECTRIC POWER COMPANY | Renewable Energy Power Purchase Agreement [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	30
2015	31
2016	31
2017	31
2018	31
Thereafter	410
Total	564
TUCSON ELECTRIC POWER COMPANY | RES Performance Based Incentives Minimum Commitment [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	8
2015	8
2016	8
2017	8
2018	8
Thereafter	83
Total	123
TUCSON ELECTRIC POWER COMPANY | Operating Lease [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
2014	3
2015	3
2016	2
2017	2
2018	2
Thereafter	14
Total	$26

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Commitments Additional Information) (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrecorded Unconditional Purchase Obligation [Line Items]	'	'	'	'
Operating Leases, Rent Expense	'	$3	$3	$3
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'	'	'	'
Duration of Power Purchase Agreement, In Years	'20 years	'	'	'
Output Purchase Requirement From Renewable Energy Facility	'	100.00%	'	'
Operating Leases, Rent Expense	'	$2	$2	$2
UNS Electric	'	'	'	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'	'	'	'
Duration of Power Purchase Agreement, In Years	'20 years	'	'	'
Output Purchase Requirement From Renewable Energy Facility	'	100.00%	'	'

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (TEP Contingencies) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013
San Juan [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Percentage of ownership in Generating Units 1 & 2	'	50.00%
Percentage of ownership in generating station	'	20.00%
Four Corner [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Percentage of ownership in generating station	'	7.00%
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]	'	'
TEP's share of reclamation costs at expiration dates of the coal supply agreements	'	$44
TEP's recorded obligations for final mine reclamation costs	16	18
TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
TEP accrued an estimated loss related to Four Corners Generating Station	'	1
TUCSON ELECTRIC POWER COMPANY | Tucson to Nogales [Member]	'	'
Commitments And Contingencies [Line Items]	'	'
Asset Impairment Charges	5	'
Regulatory Assets	'	5
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_5

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Environmental Matters) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Navajo [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	$1,000,000		'	'
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1,000,000		'	'
Estimated Capital Expenditure for Selective Catalytic Reduction	42,000,000	[1]	'	'
Estimated Capital Expenditure for Selective Non Catalytic Reduction	0	[1]	'	'
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1,000,000	[1]	'	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	0	[1]	'	'
Better Than BART Agreement Year by which to Shut Down One Unit	'2020		'	'
Better than BART Agreement, Year by which SCR Technology to be Installed	'2030		'	'
Better than BART Agreement, Year by which Coal Fired Operation will Cease	'2044		'	'
Estimated Capital Expenditure Related to Installation of Baghouses	43,000,000		'	'
Estimated Future Annual Operating Costs For Mercury Emmission Control Equipment and Baghouses	1,000,000		'	'
San Juan Unit Two [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%		'	'
Four Corner [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	1,000,000		'	'
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1,000,000		'	'
Estimated Capital Expenditure for Selective Catalytic Reduction	35,000,000	[2]	'	'
Estimated Capital Expenditure for Selective Non Catalytic Reduction	0	[2]	'	'
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2,000,000	[2]	'	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	0	[2]	'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	7.00%		'	'
Springerville [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Future Capital Cost For Mercury Emission Control Equipment	5,000,000		'	'
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	3,000,000		'	'
San Juan [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Capital Expenditure for Selective Non Catalytic Reduction	35,000,000	[3]	'	'
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	6,000,000	[3]	'	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1,000,000	[3]	'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	20.00%		'	'
Book Value of Company Share Of Generating Units	113,000,000		'	'
San Juan [Member] | Minimum [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Capital Expenditure for Selective Catalytic Reduction	180,000,000		'	'
San Juan [Member] | Maximum [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Capital Expenditure for Selective Catalytic Reduction	200,000,000		'	'
Sundt [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Capital Expenditure for Selective Catalytic Reduction	0	[2]	'	'
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12,000,000	[2]	'	'
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	0	[2]	'	'
Sundt [Member] | Minimum [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5,000,000	[2]	'	'
Sundt [Member] | Maximum [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	6,000,000	[2]	'	'
TUCSON ELECTRIC POWER COMPANY	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Environmental compliance costs capitalized in construction costs	5,000,000		2,000,000	8,000,000
Environmental Remediation Expense	8,000,000		15,000,000	12,000,000
Expected environmental expenses	5,000,000		'	'
TUCSON ELECTRIC POWER COMPANY | Sundt [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Book Value of Company Share Of Generating Units	27,000,000		'	'
TUCSON ELECTRIC POWER COMPANY | One Year In Future [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Expected environmental compliance costs to be capitalized in construction costs	12,000,000		'	'
TUCSON ELECTRIC POWER COMPANY | Two Years In Future [Member] [Member]	'		'	'
Commitments And Contingencies [Line Items]	'		'	'
Expected environmental compliance costs to be capitalized in construction costs	$36,000,000		'	'
[1]	The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.
[2]	On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.
[3]	The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 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.

POTENTIAL_PURCHASE_OF_GASFIRED1

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY Additional Information (Details) (Entegra, Gila River Generating Station Unit 3, USD $)	Feb. 25, 2014	Dec. 23, 2013
In Millions, unless otherwise specified		MW
Unusual or Infrequent Item [Line Items]	'	'
Potential Purchase of Gas-Fired Generation Facility	'	$219
Generating capacity of plant in MW	'	550
TUCSON ELECTRIC POWER COMPANY	'	'
Unusual or Infrequent Item [Line Items]	'	'
Potential Purchase of Gas-Fired Generation Facility	'	164
Generating capacity of plant in MW	'	413
Percentage of ownership in Generating Unit	'	75.00%
Letters Of Credit Potential Amount	15	'
UNS ELECTRIC, INC.	'	'
Unusual or Infrequent Item [Line Items]	'	'
Potential Purchase of Gas-Fired Generation Facility	'	$55
Generating capacity of plant in MW	'	137
Percentage of ownership in Generating Unit	'	25.00%

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	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'	'
Statutory tax rate	'	35.00%	'	'
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	'	$65,000,000	$51,000,000	$62,000,000
State Income Tax Expense, Net of Federal Deduction	'	8,000,000	7,000,000	8,000,000
Federal/State Tax Credits	'	-2,000,000	-1,000,000	-3,000,000
Allowance for Funds Used During Construction Income Tax Difference	'	-2,000,000	-1,000,000	-1,000,000
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	'	0	0	0
Investment Tax Credit Basis Difference	-11,039,000	'	0	0
Other	'	0	0	1,000,000
Income Tax Expense (Benefit)	'	58,427,000	55,727,000	66,951,000
TUCSON ELECTRIC POWER COMPANY	'	'	'	'
Income Taxes [Line Items]	'	'	'	'
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	'	52,000,000	37,000,000	48,000,000
State Income Tax Expense, Net of Federal Deduction	'	7,000,000	5,000,000	6,000,000
Federal/State Tax Credits	'	-2,000,000	-1,000,000	-2,000,000
Allowance for Funds Used During Construction Income Tax Difference	'	-1,000,000	-1,000,000	-1,000,000
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	'	2,000,000	0	0
Investment Tax Credit Basis Difference	'	-10,751,000	0	0
Other	'	1,000,000	-1,000,000	1,000,000
Income Tax Expense (Benefit)	'	$47,986,000	$39,109,000	$52,000,000

INCOME_TAXES_Income_Tax_Expens

INCOME TAXES (Income Tax Expense Included in Income Statements) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current Tax Expense (Benefit)	'	'	'
Federal	($11,000,000)	($2,000,000)	($7,000,000)
State	-2,000,000	-2,000,000	-2,000,000
Total	-13,000,000	-4,000,000	-9,000,000
Deferred Tax Expense (Benefit)	'	'	'
Federal	61,000,000	51,000,000	64,000,000
Investment Tax Credit	-1,000,000	0	-1,000,000
State	11,000,000	9,000,000	13,000,000
Total	71,000,000	60,000,000	76,000,000
Income Tax Expense (Benefit)	58,427,000	55,727,000	66,951,000
TUCSON ELECTRIC POWER COMPANY	'	'	'
Current Tax Expense (Benefit)	'	'	'
Federal	-8,000,000	-4,000,000	-5,000,000
State	-2,000,000	-2,000,000	-2,000,000
Total	-10,000,000	-6,000,000	-7,000,000
Deferred Tax Expense (Benefit)	'	'	'
Federal	47,000,000	38,000,000	50,000,000
Investment Tax Credit	-1,000,000	0	-1,000,000
State	12,000,000	7,000,000	10,000,000
Total	58,000,000	45,000,000	59,000,000
Income Tax Expense (Benefit)	$47,986,000	$39,109,000	$52,000,000

INCOME_TAXES_The_Significant_C

INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Gross Deferred Income Tax Assets	'	'
Capital Lease Obligations	$127	$141
Net Operating Loss Carryforwards	94	72
Customer Advances and Contributions in Aid of Construction	33	34
Alternative Minimum Tax Credit	43	43
Accrued Postretirement Benefits	23	23
Renewable Energy Credit Up-Front Incentive Payments	0	26
Emission Allowance Inventory	10	10
Deferred Tax Assets Unregulated Investment Losses	7	9
Other	50	44
Gross Deferred Income Tax Assets	387	402
Deferred Tax Assets Valuation Allowance	-7	-7
Gross Deferred Income Tax Liabilities	'	'
Plant - Net	-708	-648
Capital Lease Assets - Net	-47	-34
Pensions	-21	-23
PPFAC	-5	-6
Other	-21	-15
Deferred Tax Liabilities, Gross	-802	-726
Deferred Tax Liabilities, Net	-422	-331
TUCSON ELECTRIC POWER COMPANY	'	'
Gross Deferred Income Tax Assets	'	'
Capital Lease Obligations	127	141
Net Operating Loss Carryforwards	104	85
Customer Advances and Contributions in Aid of Construction	19	19
Alternative Minimum Tax Credit	24	24
Accrued Postretirement Benefits	23	23
Renewable Energy Credit Up-Front Incentive Payments	0	20
Emission Allowance Inventory	10	10
Deferred Tax Assets Unregulated Investment Losses	0	0
Other	44	43
Gross Deferred Income Tax Assets	351	365
Deferred Tax Assets Valuation Allowance	-2	0
Gross Deferred Income Tax Liabilities	'	'
Plant - Net	-615	-571
Capital Lease Assets - Net	-47	-34
Pensions	-22	-24
PPFAC	-2	-3
Other	-20	-15
Deferred Tax Liabilities, Gross	-706	-647
Deferred Tax Liabilities, Net	($357)	($282)

INCOME_TAXES_Balance_Sheets_Di

INCOME TAXES (Balance Sheets Display Net Deferred Income Tax Liability) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Income Taxes [Line Items]	'	'
Deferred Income Taxes - Current Assets	$60	$34
Deferred Tax Liabilities, Gross, Noncurrent	-482	-365
Deferred Tax Liabilities, Net	-422	-331
TUCSON ELECTRIC POWER COMPANY	'	'
Income Taxes [Line Items]	'	'
Deferred Income Taxes - Current Assets	64	37
Deferred Tax Liabilities, Gross, Noncurrent	-421	-319
Deferred Tax Liabilities, Net	($357)	($282)

INCOME_TAXES_Summary_of_Tax_Ca

INCOME TAXES (Summary of Tax Carryforwards) (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Income Tax Contingency [Line Items]	'
Capital Loss	$7
Investment Tax Credits	6
Internal Revenue Service (IRS) [Member]	'
Income Tax Contingency [Line Items]	'
Net Operating Loss Carryforward	266
State Tax Jurisdiction [Member]	'
Income Tax Contingency [Line Items]	'
Net Operating Loss Carryforward	30
Tax Credits	5
AMT Credit [Member]	'
Income Tax Contingency [Line Items]	'
Tax Credits	43
TUCSON ELECTRIC POWER COMPANY	'
Income Tax Contingency [Line Items]	'
Capital Loss	0
Investment Tax Credits	6
TUCSON ELECTRIC POWER COMPANY | Internal Revenue Service (IRS) [Member]	'
Income Tax Contingency [Line Items]	'
Net Operating Loss Carryforward	286
TUCSON ELECTRIC POWER COMPANY | State Tax Jurisdiction [Member]	'
Income Tax Contingency [Line Items]	'
Net Operating Loss Carryforward	99
Tax Credits	6
TUCSON ELECTRIC POWER COMPANY | AMT Credit [Member]	'
Income Tax Contingency [Line Items]	'
Tax Credits	$24

INCOME_TAXES_Uncertain_Tax_Pos

INCOME TAXES (Uncertain Tax Positions) (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Feb. 28, 2013	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits, Beginning of Year	'	$30	$29
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	'	2	5
Reductions Based on Settlements with Tax Authorities	-28	-28	-4
Unrecognized Tax Benefits, End of Year	'	4	30
TUCSON ELECTRIC POWER COMPANY	'	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits, Beginning of Year	'	23	24
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	'	1	3
Reductions Based on Settlements with Tax Authorities	-22	-22	-4
Unrecognized Tax Benefits, End of Year	'	$2	$23

INCOME_TAXES_Additional_Inform

INCOME TAXES (Additional Information) (Detail) (USD $)	1 Months Ended	12 Months Ended
	Feb. 28, 2013	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]	'	'	'
Unregulated investment loss	'	($7,000,000)	($7,000,000)
Deferred Tax Asset Valuation Allowance	'	7,000,000	7,000,000
Proceeds and Excess Tax Benefit from Share-based Compensation	'	4,000,000	'
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	'	'	1,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	'	0	1,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	'	0	'
Unrecognized Tax Benefits, Interest on Income Taxes Expense	'	1,000,000	0
Reductions Based on Settlements with Tax Authorities	-28,000,000	-28,000,000	-4,000,000
Change In Deferred Tax Liabilities And Deferred Tax Assets Related To Tangible Property	'	4,000,000	'
Internal Revenue Service (IRS) [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Operating Loss Carryforwards	'	266,000,000	'
TUCSON ELECTRIC POWER COMPANY	'	'	'
Income Taxes [Line Items]	'	'	'
Deferred Tax Asset Valuation Allowance	'	2,000,000	0
Reductions Based on Settlements with Tax Authorities	-22,000,000	-22,000,000	-4,000,000
TUCSON ELECTRIC POWER COMPANY | Internal Revenue Service (IRS) [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Operating Loss Carryforwards	'	$286,000,000	'

EMPLOYEE_BENEFIT_PLANS_Additio

EMPLOYEE BENEFIT PLANS (Additional Information) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Percentage of net periodic benefit cost that was capitalized	21.00%	'	'
Level 3 [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Index value percentage of real estate assets	85.00%	87.00%	'
Other Retiree Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Pension plan contributions	$6	$5	'
Pension Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Pension plan contributions	23	23	'
Defined Benefit Plan, Accumulated Benefit Obligation	314	334	'
TUCSON ELECTRIC POWER COMPANY	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Matching 401(k) contributions made	5	5	5
TUCSON ELECTRIC POWER COMPANY | Other Retiree Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Pension plan contributions	6	5	'
TUCSON ELECTRIC POWER COMPANY | Pension Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Pension plan contributions	22	20	'
UNS Gas and UNS Electric [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Expected annual benefit payment for 2014-2018	7	'	'
Expected annual benefit payment for 2019-2023	9	'	'
Matching 401(k) contributions made	1	1	1
Other Retiree Benefits [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Effect of plan amendment on obligation	'	1	'
Pension Benefits [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Effect of plan amendment on obligation	'	1	'
Effect of Plan Amendment on Future Payments	'	5	'
VEBA Trust [Member] | TUCSON ELECTRIC POWER COMPANY | Other Retiree Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Pension plan contributions	$3	$3	$2

EMPLOYEE_BENEFIT_PLANS_Pension

EMPLOYEE BENEFIT PLANS (Pension and Other Retiree Benefit Related Amounts) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Benefits [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Regulatory Pension Asset Included in Other Regulatory Assets	$75	$129
Accrued Benefit Liability Included in Accrued Employee Expenses	-1	-1
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	-28	-90
Accumulated Other Comprehensive Loss (related to SERP)	2	4
Net Amount Recognized	48	42
Other Retiree Benefits [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Regulatory Pension Asset Included in Other Regulatory Assets	4	10
Accrued Benefit Liability Included in Accrued Employee Expenses	-2	-2
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	-63	-69
Accumulated Other Comprehensive Loss (related to SERP)	0	0
Net Amount Recognized	-61	-61
UNS Gas and UNS Electric [Member] | Pension Benefits [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Accrued pension benefit liability	5	9
UNS Gas and UNS Electric [Member] | Other Retiree Benefits [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Accrued pension benefit liability	$1	$1

EMPLOYEE_BENEFIT_PLANS_Change_

EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Projected Benefit Obligation	'	'	'
Interest Cost	'	$15	'
Service Cost	3	'	'
Change in Plan Assets	'	'	'
Fair Value Beginning Balance	289	'	'
Fair Value Ending Balance	323	289	'
Pension Benefits [Member]	'	'	'
Change in Projected Benefit Obligation	'	'	'
Benefit Obligation at Beginning of Year	380	319	'
Actuarial (Gain) Loss	-38	51	'
Interest Cost	15	16	15
Service Cost	13	10	10
Benefits Paid	-18	-15	'
Projected Benefit Obligation at End of Year	352	380	319
Change in Plan Assets	'	'	'
Fair Value Beginning Balance	289	245	'
Actual Return on Plan Assets	29	36	'
Benefits Paid	-18	-15	'
Employer Contributions	23	23	'
Fair Value Ending Balance	323	289	245
Funded Status at End of Year	-29	-91	'
Other Retiree Benefits [Member]	'	'	'
Change in Projected Benefit Obligation	'	'	'
Benefit Obligation at Beginning of Year	78	73	'
Actuarial (Gain) Loss	-5	3	'
Interest Cost	3	3	4
Service Cost	4	3	3
Benefits Paid	-4	-4	'
Projected Benefit Obligation at End of Year	75	78	73
Change in Plan Assets	'	'	'
Fair Value Beginning Balance	7	5	'
Actual Return on Plan Assets	1	1	'
Benefits Paid	-4	-4	'
Employer Contributions	6	5	'
Fair Value Ending Balance	10	7	5
Funded Status at End of Year	-65	-71	'
TUCSON ELECTRIC POWER COMPANY | Pension Benefits [Member]	'	'	'
Change in Plan Assets	'	'	'
Employer Contributions	22	20	'
TUCSON ELECTRIC POWER COMPANY | Other Retiree Benefits [Member]	'	'	'
Change in Plan Assets	'	'	'
Employer Contributions	$6	$5	'

EMPLOYEE_BENEFIT_PLANS_Change_1

EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Parenthetical) (Detail) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2014

In Millions, unless otherwise specified

UNS Gas and UNS Electric [Member]

UNS Gas and UNS Electric [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Other Retiree Benefits [Member]

Other Retiree Benefits [Member]

Other Retiree Benefits [Member]

Other Retiree Benefits [Member]

Other Retiree Benefits [Member]

Other Retiree Benefits [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Gas and UNS Electric [Member]

UNS Gas and UNS Electric [Member]

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

UNS Gas and UNS Electric [Member]

Pension Benefits [Member]

Pension Benefits [Member]

TUCSON ELECTRIC POWER COMPANY

Funded Status And Amount Recognized In Balance Sheet And Statement Of Operations [Line items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pension plan contributions

'

'

'

'

$23

$23

'

$22

$20

'

'

$6

$5

'

$6

$5

'

'

'

Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

9

Pension benefit obligations

'

'

'

'

352

380

319

'

'

21

23

75

78

73

'

'

1

'

'

Defined Benefit Plan, Fair Value of Plan Assets

$323

$289

$16

$14

$323

$289

$245

'

'

'

'

$10

$7

$5

'

'

'

'

'

EMPLOYEE_BENEFIT_PLANS_Compone

EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Net Loss	$77	$133
Prior Service Cost (Benefit)	0	1
Other Retiree Benefits [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Net Loss	7	13
Prior Service Cost (Benefit)	($3)	($3)

EMPLOYEE_BENEFIT_PLANS_Informa

EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Detail) (Pension Benefits [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Benefits [Member]	'	'
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]	'	'
Accumulated Benefit Obligation at End of Year	$30	$334
Fair Value of Plan Assets at End of Year	$16	$289

EMPLOYEE_BENEFIT_PLANS_Compone1

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service Cost	$3	'	'
Interest Cost	'	15	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service Cost	13	10	10
Interest Cost	15	16	15
Expected Return on Plan Assets	-20	-17	-16
Prior Service Cost Amortization	0	0	0
Amortization of Actuarial (Gain) Loss	9	7	6
Net Periodic Benefit Plan Cost	17	16	15
Other Retiree Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service Cost	4	3	3
Interest Cost	3	3	4
Expected Return on Plan Assets	-1	0	0
Prior Service Cost Amortization	-1	0	-1
Amortization of Actuarial (Gain) Loss	1	0	0
Net Periodic Benefit Plan Cost	$6	$6	$6

EMPLOYEE_BENEFIT_PLANS_Changes

EMPLOYEE BENEFIT PLANS (Changes in Plan Assets and Benefit Obligations Recognized) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Amortization of Prior Service (Cost) Credit	($1,488,000)	'	'
Other Retiree Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Prior Service Cost (Credit)	-1,000,000	0	-1,000,000
Current Year Actuarial (Gain) Loss	-7,000,000	-13,000,000	'
Amortization of Actuarial (Gain) Loss	-1,000,000	0	0
Other Retiree Benefits [Member] | Regulatory Asset [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Prior Service Cost (Credit)	0	0	-2,000,000
Current Year Actuarial (Gain) Loss	-6,000,000	2,000,000	0
Amortization of Actuarial (Gain) Loss	1,000,000	0	0
Amortization of Prior Service (Cost) Credit	1,000,000	0	1,000,000
Total Recognized (Gain) Loss	-6,000,000	2,000,000	-1,000,000
Amortization of estimated net loss in 2014	1,000,000	'	'
Pension Benefits [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Prior Service Cost (Credit)	0	0	0
Current Year Actuarial (Gain) Loss	-77,000,000	-133,000,000	'
Amortization of Actuarial (Gain) Loss	-9,000,000	-7,000,000	-6,000,000
Pension Benefits [Member] | Regulatory Asset [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Current Year Actuarial (Gain) Loss	-46,000,000	30,000,000	25,000,000
Amortization of Actuarial (Gain) Loss	8,000,000	7,000,000	5,000,000
Total Recognized (Gain) Loss	-54,000,000	23,000,000	20,000,000
Estimated gain (loss) that will be amortized in the net periodic benefit cost in 2014	4,000,000	'	'
Amortization of estimated net loss in 2014	1,000,000	'	'
Pension Benefits [Member] | Accumulated Other Comprehensive Loss [Member]	'	'	'
Pension Plans, Postretirement and Other Employee Benefits [Line Items]	'	'	'
Current Year Actuarial (Gain) Loss	-1,000,000	1,000,000	-2,000,000
Amortization of Actuarial (Gain) Loss	0	0	0
Total Recognized (Gain) Loss	-1,000,000	1,000,000	-2,000,000
Amortization of estimated net loss in 2014	$1,000,000	'	'

EMPLOYEE_BENEFIT_PLANS_Weighte

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Detail)	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,	'	'
Rate of Compensation Increase	3.00%	3.00%
Pension Benefits [Member] | Minimum [Member]	'	'
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,	'	'
Discount Rate	5.00%	4.10%
Pension Benefits [Member] | Maximum [Member]	'	'
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,	'	'
Discount Rate	5.20%	4.30%
Other Retiree Benefits [Member]	'	'
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,	'	'
Discount Rate	4.70%	3.80%

EMPLOYEE_BENEFIT_PLANS_Weighte1

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Rate of Compensation Increase	3.00%	3.00%	'
Expected Return on Plan Assets	7.00%	7.00%	7.00%
Pension Benefits [Member] | Minimum [Member]	'	'	'
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount Rate	4.10%	4.90%	5.50%
Rate of Compensation Increase	'	'	3.00%
Pension Benefits [Member] | Maximum [Member]	'	'	'
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount Rate	4.30%	5.00%	5.60%
Rate of Compensation Increase	'	'	5.00%
Other Retiree Benefits [Member]	'	'	'
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount Rate	3.80%	4.70%	5.20%
Expected Return on Plan Assets	7.00%	7.00%	5.10%

EMPLOYEE_BENEFIT_PLANS_Assumed

EMPLOYEE BENEFIT PLANS (Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]	'	'
Health Care Cost Trend Rate Assumed for Next Year	6.70%	6.90%
Ultimate Health Care Cost Trend Rate Assumed	4.50%	4.50%
Year that the Rate Reaches the Ultimate Trend Rate	'2027	'2027

EMPLOYEE_BENEFIT_PLANS_OnePerc

EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Line Items]	'
Effect of one percentage point increase on service and interest cost components	$1
Effect of one percentage point decrease on service and interest cost components	-1
Effect on Retiree Benefit Obligation, One-Percentage-Point Increase	6
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease	($5)

EMPLOYEE_BENEFIT_PLANS_Pension1

EMPLOYEE BENEFIT PLANS (Pension Plan Asset Allocations) (Detail)	Dec. 31, 2013	Dec. 31, 2012
TUCSON ELECTRIC POWER COMPANY	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	100.00%	100.00%
TUCSON ELECTRIC POWER COMPANY | Equity Securities	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	50.00%	50.00%
TUCSON ELECTRIC POWER COMPANY | Fixed Income	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	40.00%	41.00%
TUCSON ELECTRIC POWER COMPANY | Real Estate	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	7.00%	7.00%
TUCSON ELECTRIC POWER COMPANY | Other	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	3.00%	2.00%
UNS Gas and UNS Electric [Member]	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	100.00%	100.00%
UNS Gas and UNS Electric [Member] | Equity Securities	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	50.00%	56.00%
UNS Gas and UNS Electric [Member] | Fixed Income	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	40.00%	33.00%
UNS Gas and UNS Electric [Member] | Real Estate	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	10.00%	11.00%
UNS Gas and UNS Electric [Member] | Other	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'
Pension plan assets allocation	0.00%	0.00%

EMPLOYEE_BENEFIT_PLANS_Fair_Va

EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Pension Plan Assets) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	$323	$289	'
Level 3 [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	21	19	15
Level 3 [Member] | Real Estate	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	14	13	11
Level 3 [Member] | Private Equity	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	7	6	4
Other Retiree Benefits [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	10	7	5
Fair Value Measurements of Pension Assets [Member] | Cash Equivalents	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	1	1	'
Fair Value Measurements of Pension Assets [Member] | United States Large Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	80	71	'
Fair Value Measurements of Pension Assets [Member] | United States Small Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	17	15	'
Fair Value Measurements of Pension Assets [Member] | Non-United States	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	65	59	'
Fair Value Measurements of Pension Assets [Member] | Fixed Income	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	130	116	'
Fair Value Measurements of Pension Assets [Member] | Real Estate	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	23	21	'
Fair Value Measurements of Pension Assets [Member] | Private Equity	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	7	6	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	1	1	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Cash Equivalents	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	1	1	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | United States Large Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | United States Small Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Non-United States	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Fixed Income	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Real Estate	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Private Equity	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	301	269	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Cash Equivalents	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | United States Large Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	80	71	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | United States Small Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	17	15	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Non-United States	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	65	59	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Fixed Income	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	130	116	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Real Estate	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	9	8	'
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Private Equity	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	21	19	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Cash Equivalents	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | United States Large Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | United States Small Cap	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Non-United States	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Fixed Income	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	0	0	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Real Estate	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	14	13	'
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Private Equity	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	7	6	'
Uns Gas And Uns Electric [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	16	14	'
Uns Gas And Uns Electric [Member] | Level 2 [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	16	14	'
VEBA Trust [Member] | Other Retiree Benefits [Member]	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	10	7	'
VEBA Trust [Member] | Other Retiree Benefits [Member] | Fixed Income	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	4	3	'
VEBA Trust [Member] | Other Retiree Benefits [Member] | VEBA Trust Asset - Equities	'	'	'
Pension And Other Employee Benefit Plans [Line Items]	'	'	'
Fair value measurements of plan assets	$6	$4	'

EMPLOYEE_BENEFIT_PLANS_Reconci

EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Pension Assets) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Actual Return on Plan Assets:	'	'
Fair Value Ending Balance	$323	$289
Level 3 [Member]	'	'
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'
Fair Value Beginning Balance	19	15
Actual Return on Plan Assets:	'	'
Assets Held at Reporting Date	2	3
Purchases, Sales, and Settlements	0	1
Fair Value Ending Balance	21	19
Private Equity | Level 3 [Member]	'	'
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'
Fair Value Beginning Balance	6	4
Actual Return on Plan Assets:	'	'
Assets Held at Reporting Date	1	1
Purchases, Sales, and Settlements	0	1
Fair Value Ending Balance	7	6
Real Estate | Level 3 [Member]	'	'
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'
Fair Value Beginning Balance	13	11
Actual Return on Plan Assets:	'	'
Assets Held at Reporting Date	1	2
Purchases, Sales, and Settlements	0	0
Fair Value Ending Balance	$14	$13

EMPLOYEE_BENEFIT_PLANS_Target_

EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Detail)	12 Months Ended
	Dec. 31, 2013
TUCSON ELECTRIC POWER COMPANY	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	100.00%
TUCSON ELECTRIC POWER COMPANY | Fixed Income	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	41.00%
TUCSON ELECTRIC POWER COMPANY | United States Large Cap	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	24.00%
TUCSON ELECTRIC POWER COMPANY | Non-United States Developed	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	15.00%
TUCSON ELECTRIC POWER COMPANY | Real Estate	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	8.00%
TUCSON ELECTRIC POWER COMPANY | United States Small Cap	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	5.00%
TUCSON ELECTRIC POWER COMPANY | Non-United States Emerging	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	5.00%
TUCSON ELECTRIC POWER COMPANY | Private Equity	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	2.00%
TUCSON ELECTRIC POWER COMPANY | Cash/Treasury Bills	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	0.00%
UNS Gas and UNS Electric [Member]	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	100.00%
UNS Gas and UNS Electric [Member] | Fixed Income	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	42.00%
UNS Gas and UNS Electric [Member] | United States Large Cap	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	24.00%
UNS Gas and UNS Electric [Member] | Non-United States Developed	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	14.00%
UNS Gas and UNS Electric [Member] | Real Estate	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	10.00%
UNS Gas and UNS Electric [Member] | United States Small Cap	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	5.00%
UNS Gas and UNS Electric [Member] | Non-United States Emerging	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	5.00%
UNS Gas and UNS Electric [Member] | Private Equity	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	0.00%
UNS Gas and UNS Electric [Member] | Cash/Treasury Bills	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	0.00%
VEBA Trust [Member]	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	100.00%
VEBA Trust [Member] | Fixed Income	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	38.00%
VEBA Trust [Member] | United States Large Cap	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	39.00%
VEBA Trust [Member] | Non-United States Developed	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	7.00%
VEBA Trust [Member] | Real Estate	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	0.00%
VEBA Trust [Member] | United States Small Cap	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	5.00%
VEBA Trust [Member] | Non-United States Emerging	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	9.00%
VEBA Trust [Member] | Private Equity	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	0.00%
VEBA Trust [Member] | Cash/Treasury Bills	'
Pension And Other Employee Benefit Plans [Line Items]	'
Target allocation percentage of plan assets	2.00%

EMPLOYEE_BENEFIT_PLANS_Benefit

EMPLOYEE BENEFIT PLANS (Benefit Payments by Defined Pension Plans and Retiree Plan) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Benefits [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'
2014	$15
2015	16
2016	17
2017	18
2018	20
Years 2019-2023	114
Other Retiree Benefits [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'
2014	5
2015	5
2016	5
2017	5
2018	5
Years 2019-2023	$29

SHAREBASED_COMPENSATION_PLANS_1

SHARE-BASED COMPENSATION PLANS (Summary of Stock Option Activity) (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Shares	'	'	'
Outstanding, Beginning balance	409	581	921
Exercised, Shares	-127	-132	-319
Forfeited/Expired, Shares	0	-40	-21
Outstanding, Ending balance	282	409	581
Exercisable, End of Year, Shares	282	409	508
Weighted Average Exercise Price	'	'	'
Outstanding, Beginning balance	$29.09	$29.11	$27.96
Exercised	$30.12	$26.54	$25.60
Forfeited/Expired	$0	$37.88	$31.92
Outstanding, Ending balance	$28.63	$29.09	$29.11
Exercisable, End of Year	$28.63	$29.09	$29.53
Aggregate Intrinsic Value of Options Exercised ($000s)	$2,897	$1,878	$3,690
Aggregate Intrinsic Value for Options Outstanding ($000s)	8,795	'	'
Aggregate Intrinsic Value for Options Exercisable ($000s)	$8,795	'	'
Weighted Average Remaining Contractual Term of Outstanding Options	'4 years 1 month 6 days	'	'
Weighted Average Remaining Contractual Term of Exercisable Options	'4 years 1 month 6 days	'	'
$26.11 - $37.88 [Member]	'	'	'
Shares	'	'	'
Outstanding, Ending balance	282	'	'
Exercisable, End of Year, Shares	282	'	'
Weighted Average Exercise Price	'	'	'
Outstanding, Ending balance	$28.63	'	'
Exercisable, End of Year	$28.63	'	'
Weighted Average Remaining Contractual Term of Outstanding Options	'4 years 1 month 6 days	'	'

SHAREBASED_COMPENSATION_PLANS_2

SHARE-BASED COMPENSATION PLANS (Restricted Stock Units) (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Director [Member]	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'
Granted, Shares	8,870	15,303	14,655
Grant Date Fair Value	$48.99	$35.94	$37.53
Management [Member]	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'
Granted, Shares	21,560	'	'
Grant Date Fair Value	$46.23	'	'

SHAREBASED_COMPENSATION_PLANS_3

SHARE-BASED COMPENSATION PLANS (Summary of Performance Shares Awarded and Grant Date Fair Value) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Granted, Shares	52,000	'	'
Grant Date Fair Value	44.94	'	'
Performance period description	'three-year	'	'
Number of shares that vested during the period	52,000	'	'
Performance Share Awards [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Granted, Shares	43,120	80,140	80,440
Market Condition Awards [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Grant Date Fair Value	45.54	32.71	33.73
Vesting based on goal attainment	57.80%	'	'
Performance Condition [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Grant Date Fair Value	46.23	36.4	36.58
Vesting based on goal attainment	150.00%	'	'
Performance Period Ending in Current Year [Member] | Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares that vested during the period	68,158	'	'
Number of shares unearned and forfeited	28,682	'	'
Dividend Equivalents [Member] | Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares that vested during the period	8,521	'	'

SHAREBASED_COMPENSATION_PLANS_4

SHARE-BASED COMPENSATION PLANS (Summary of Performance and Restricted Share Awards) (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock Units (RSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$574	$550	$495
Non-vested, beginning balance	15,000	'	'
Granted, Shares	31,000	'	'
Number of shares that vested during the period	16,000	'	'
Forfeited, Shares	-2,000	'	'
Non-vested, ending balance	28,000	15,000	'
Non-vested, beginning balance	$35.94	'	'
Granted	$47.04	'	'
Vested	$36.27	'	'
Forfeited	$46.23	'	'
Non-vested, ending balance	$47.12	$35.94	'
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$2,387	$2,377	$1,069
Non-vested, beginning balance	145,000	'	'
Granted, Shares	52,000	'	'
Number of shares that vested during the period	52,000	'	'
Forfeited, Shares	-32,000	'	'
Non-vested, ending balance	113,000	145,000	'
Non-vested, beginning balance	$34.83	'	'
Granted	$44.94	'	'
Vested	$35.35	'	'
Forfeited	$37.57	'	'
Non-vested, ending balance	$38.45	$34.83	'

SHAREBASED_COMPENSATION_PLANS_5

SHARE-BASED COMPENSATION PLANS (Additional Information) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share based compensation expense, net of amounts capitalized	$3,000,000	$3,000,000	$3,000,000
Tax deduction realized from exercise of share-based payment arrangements	0	500,000	0
Total unrecognized compensation expense on non-vested share-based compensation	3,000,000	'	'
Number of shares awarded but not yet issued under share based compensation arrangements	500,000	'	'
TUCSON ELECTRIC POWER COMPANY	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share based compensation expense, net of amounts capitalized	'	$2,000,000	$2,000,000
Restricted Stock Units (RSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares that vested during the period	16,000	'	'
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares that vested during the period	52,000	'	'
Omnibus Stock And Incentive Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Shares available for grants under the 2011 Plan	1,200,000	'	'
Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Common stock shares issued	57,253	31,058	56,705
Dividend Equivalents [Member] | Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares that vested during the period	8,521	'	'

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

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Numerator:

'

'

'

'

'

'

'

'

'

'

'

Net Income

$13,525

$67,990

$34,618

$11,345

$7,506

$50,664

$26,273

$6,476

$127,478

$90,919

$109,975

Interest on Convertible Debt, Net of Tax

'

'

'

'

'

'

'

'

0

[1]

1,100

[1]

4,390

[1]

Adjusted Net Income Available for Diluted Common Stock Outstanding

'

'

'

'

'

'

'

'

$127,478

$92,019

$114,365

Weighted Average Shares of Common Stock Outstanding:

'

'

'

'

'

'

'

'

'

'

'

Common Shares Issued

'

'

'

'

'

'

'

'

41,446

40,212

36,780

Fully Vested Deferred Stock Units

'

'

'

'

'

'

'

'

172

150

129

Participating Securities

'

'

'

'

'

'

'

'

0

0

53

Total Weighted Average Shares of Common Stock Outstanding and Participating Securities - Basic

'

'

'

'

'

'

'

'

41,618

40,362

36,962

Effect of Dilutive Securities:

'

'

'

'

'

'

'

'

'

'

'

Convertible Senior Notes

'

'

'

'

'

'

'

'

0

[1]

1,062

[1]

4,281

[1]

Options and Stock Issuable Under Share-Based Compensation Plans

'

'

'

'

'

'

'

'

357

331

366

Total Shares - Diluted

'

'

'

'

'

'

'

'

41,975

41,755

41,609

[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)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	50	153
Stock Options [Member]	'	'	'
Anti-Dilutive Shares Excluded from the Diluted EPS Computation	0	50	153
Restricted Stock Units (RSUs) [Member]	'	'	'
Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	0	0

STOCKHOLDERS_EQUITY_Additional

STOCKHOLDERS' EQUITY (Additional Information) (Detail) (USD $)	12 Months Ended							1 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Feb. 25, 2014
				TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	TUCSON ELECTRIC POWER COMPANY	Convertible Debt [Member]	Subsequent Event [Member]
							UNS Energy
Class of Stock [Line Items]	'	'	'	'	'	'	'	'
Dividends declared (usd per share)	$1.74	$1.72	$1.68	'	'	'	'	$0.48
Dividend payable	'	'	'	'	'	'	'	$20,000,000
Converted notes principal	'	'	'	'	'	'	147,000,000	'
UNS Energy common stock	'	'	'	'	'	'	4,300	'
Dividends paid to UNS energy	'	'	'	40,000,000	30,000,000	0	'	'
Equity investment from parent	$0	$0	$30,000,000	$0	$0	$30,000,000	'	'

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

12 Months Ended

In Thousands, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Supplemental Cash Flow Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

'

$13,525

$67,990

$34,618

$11,345

$7,506

$50,664

$26,273

$6,476

$127,478

$90,919

$109,975

Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation Expense

'

'

'

'

'

'

'

'

'

149,615

141,303

133,832

Amortization Expense

'

'

'

'

'

'

'

'

'

27,557

35,784

30,983

Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense

'

'

'

'

'

'

'

'

'

7,288

6,622

6,140

Amortization of Deferred Debt-Related Costs Included in Interest Expense

'

'

'

'

'

'

'

'

'

3,050

3,000

3,985

Provision for Retail Customer Bad Debts

'

'

'

'

'

'

'

'

'

2,263

2,767

2,072

Use of RECs for Compliance

'

'

'

'

'

'

'

'

'

17,706

5,935

5,695

Deferred Income Taxes

'

'

'

'

'

'

'

'

'

83,501

60,264

75,515

Investment Tax Credit Basis Adjustment

-11,039

'

'

'

'

'

'

'

'

'

0

0

Pension and Postretirement Expense

'

'

'

'

'

'

'

'

'

22,783

21,856

21,202

Pension and Postretirement Funding

'

'

'

'

'

'

'

'

'

-29,161

-29,058

-28,775

Share-Based Compensation Expense

'

'

'

'

'

'

'

'

'

3,399

2,573

2,599

Allowance for Equity Funds Used During Construction

'

'

'

'

'

'

'

'

'

-6,190

-3,464

-4,496

Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment

'

'

'

'

'

'

'

'

'

-16,313

32,246

-4,932

PPFAC Reduction - TEP Rate Order

'

'

'

'

'

'

'

'

'

3,000

0

0

Competition Transition Charge Revenue Refunded

'

'

'

'

'

'

'

'

'

0

0

-35,958

Partial Write-off of Tucson to Nogales Transmission Line

'

'

'

'

'

'

'

'

'

0

4,668

0

Liquidated Damages for Springerville Unit 3 Outage

'

'

'

'

'

'

'

'

'

0

2,050

0

Gain on Settlement of El Paso Electric Dispute

'

'

'

'

'

'

'

'

'

0

0

-7,391

Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately

'

'

'

'

'

'

'

'

'

'

'

'

Accounts Receivable

'

'

'

'

'

'

'

'

'

-6,338

3,369

2,743

Materials and Fuel Inventory

'

'

'

'

'

'

'

'

'

16,197

-39,429

-20,864

Accounts Payable

'

'

'

'

'

'

'

'

'

3,223

595

8,792

Income Taxes

'

'

'

'

'

'

'

'

'

-15,868

-11,557

-2,739

Interest Accrued

'

'

'

'

'

'

'

'

'

4,875

6,922

14,344

Taxes Other Than Income Taxes

'

'

'

'

'

'

'

'

'

1,941

-58

2,857

Increase (Decrease) in Regulatory Liabilities

'

'

'

'

'

'

'

'

'

11,124

-684

2,644

Other

'

'

'

'

'

'

'

'

'

20,421

11,486

19,097

Net Cash Flows—Operating Activities

'

'

'

'

'

'

'

'

'

420,512

348,109

337,320

TUCSON ELECTRIC POWER COMPANY

'

'

'

'

'

'

'

'

'

'

'

'

Supplemental Cash Flow Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

'

4,910

64,167

30,787

1,478

452

44,569

21,910

-1,461

101,342

65,470

85,334

Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation Expense

'

'

'

'

'

'

'

'

'

118,076

110,931

104,894

Amortization Expense

'

'

'

'

'

'

'

'

'

31,294

39,493

34,650

Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense

'

'

'

'

'

'

'

'

'

6,219

5,384

4,509

Amortization of Deferred Debt-Related Costs Included in Interest Expense

'

'

'

'

'

'

'

'

'

2,452

2,227

2,378

Provision for Retail Customer Bad Debts

'

'

'

'

'

'

'

'

'

1,678

1,871

1,447

Use of RECs for Compliance

'

'

'

'

'

'

'

'

'

15,990

5,071

5,190

Deferred Income Taxes

'

'

'

'

'

'

'

'

'

69,950

45,232

59,309

Investment Tax Credit Basis Adjustment

'

'

'

'

'

'

'

'

'

-10,751

0

0

Pension and Postretirement Expense

'

'

'

'

'

'

'

'

'

19,878

19,289

18,816

Pension and Postretirement Funding

'

'

'

'

'

'

'

'

'

-27,636

-25,899

-25,878

Share-Based Compensation Expense

'

'

'

'

'

'

'

'

'

2,709

2,029

2,027

Allowance for Equity Funds Used During Construction

'

'

'

'

'

'

'

'

'

-4,526

-2,840

-3,842

Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment

'

'

'

'

'

'

'

'

'

-12,458

31,113

-6,165

PPFAC Reduction - TEP Rate Order

3,000

'

'

'

'

'

'

'

'

3,000

0

0

Competition Transition Charge Revenue Refunded

'

'

'

'

'

'

'

'

'

0

0

-35,958

Partial Write-off of Tucson to Nogales Transmission Line

'

'

'

'

'

'

'

'

'

0

4,484

0

Liquidated Damages for Springerville Unit 3 Outage

'

'

'

'

'

'

'

'

'

0

2,050

0

Gain on Settlement of El Paso Electric Dispute

'

'

'

'

'

'

'

'

'

0

0

-7,391

Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately

'

'

'

'

'

'

'

'

'

'

'

'

Accounts Receivable

'

'

'

'

'

'

'

'

'

-6,041

-871

4,809

Materials and Fuel Inventory

'

'

'

'

'

'

'

'

'

16,145

-38,384

-19,789

Accounts Payable

'

'

'

'

'

'

'

'

'

334

1,115

14,561

Income Taxes

'

'

'

'

'

'

'

'

'

-10,790

-11,421

-5,582

Interest Accrued

'

'

'

'

'

'

'

'

'

4,859

8,055

14,268

Taxes Other Than Income Taxes

'

'

'

'

'

'

'

'

'

1,425

905

2,282

Increase (Decrease) in Regulatory Liabilities

'

'

'

'

'

'

'

'

'

3,331

-3,040

303

Other

'

'

'

'

'

'

'

'

'

19,711

5,655

18,122

Net Cash Flows—Operating Activities

'

'

'

'

'

'

'

'

'

$346,191

$267,919

$268,294

SUPPLEMENTAL_CASH_FLOW_INFORMA3

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Oct. 31, 2013

Dec. 31, 2012

Dec. 31, 2005

Apr. 30, 2013

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2012

Mar. 31, 2013

Sep. 30, 2012

Nov. 30, 2013

UNS Energy

UNS Energy

Springerville Unit One Lease [Member]

Convertible Debt [Member]

Convertible Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Variable Rate Bonds [Member]

TUCSON ELECTRIC POWER COMPANY

UNS Energy

UNS Energy

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

TUCSON ELECTRIC POWER COMPANY

Unsecured Debt [Member]

TUCSON ELECTRIC POWER COMPANY

Document Fiscal Year Focus

'2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Capital Lease Obligation

'

'

'

'

'

$55,000,000

'

'

'

'

'

'

'

'

'

Debt instrument, face amount

'

'

'

'

'

'

'

150,000,000

'

16,000,000

177,000,000

'

91,000,000

150,000,000

100,000,000

Debt extinguishment

'

'

'

'

'

'

'

'

91,000,000

16,000,000

184,000,000

193,000,000

'

'

'

Converted Notes principal

'

'

'

'

'

'

147,000,000

'

'

'

'

'

'

'

'

(Decrease)/Increase to Utility Plant Accruals

4,995,000

[1]

4,813,000

[1]

-2,741,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

Net Cost Of Removal Of Interim Retirements

25,182,000

[2]

35,983,000

[2]

31,626,000

[2]

'

'

'

'

'

'

'

'

'

'

'

'

Change In Capital Lease Obligations

9,039,000

[3]

11,967,000

[3]

15,162,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

Asset Retirement Obligations

$8,064,000

[4]

$789,000

[4]

$7,638,000

[4]

$1,000,000

$0

'

'

'

'

'

'

'

'

'

'

[1]

The non-cash additions to Utility Plant represent accruals for capital expenditures.

[2]

The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.

[3]

The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.

[4]

The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

FAIR_VALUE_MEASUREMENTS_DERIVA2

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Schedule of Fair Value Measurements of Financial Assets and Liabilities) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'		'
Cash Equivalent	$14	[1]	$20	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	7	[3]	7	[3]
Total Assets	45		53
Liabilities	'		'
Liabilities	-15		-27
Net Total Assets (Liability)	30		26
Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-7	[3]	-15	[3]
Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-7	[4]	-10	[4]
TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	1	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	2	[3]	3	[3]
Total Assets	26		30
Liabilities	'		'
Liabilities	-10		-15
Net Total Assets (Liability)	16		15
TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[3]	-3	[3]
TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-7	[4]	-10	[4]
Level 1 [Member]	'		'
Assets	'		'
Cash Equivalent	14	[1]	20	[1]
Restricted Cash	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	16		27
Liabilities	'		'
Liabilities	0		0
Net Total Assets (Liability)	16		27
Level 1 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	1	[1]
Restricted Cash	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	2		8
Liabilities	'		'
Liabilities	0		0
Net Total Assets (Liability)	2		8
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Level 2 [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	3	[3]	2	[3]
Total Assets	25		21
Liabilities	'		'
Liabilities	-9		-17
Net Total Assets (Liability)	16		4
Level 2 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[3]	-7	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-7	[4]	-10	[4]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	1	[3]	1	[3]
Total Assets	23		20
Liabilities	'		'
Liabilities	-7		-13
Net Total Assets (Liability)	16		7
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	-3	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-7	[4]	-10	[4]
Level 3 [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	4	[3]	5	[3]
Total Assets	4		5
Liabilities	'		'
Derivative Liability	6		'
Liabilities	-6		-10
Net Total Assets (Liability)	-2		-5
Level 3 [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-5	[3]	-8	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Level 3 [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	1	[3]	2	[3]
Total Assets	1		2
Liabilities	'		'
Liabilities	-3		-2
Net Total Assets (Liability)	-2		0
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[3]	0	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4]	0	[4]
Netting [Member]	'		'
Assets	'		'
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	-5	[3],[5]	-5	[3],[5]
Total Assets	-5	[5]	-5	[5]
Liabilities	'		'
Liabilities	5	[5]	5	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	5	[3],[5]	5	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4],[5]	0	[4],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	-1	[3],[5]	-1	[3],[5]
Total Assets	-1	[5]	-1	[5]
Liabilities	'		'
Liabilities	1	[5]	1	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	1	[3],[5]	1	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	0	[4],[5]	0	[4],[5]
Net Fair Value [Member]	'		'
Assets	'		'
Cash Equivalent	14	[1]	20	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	2	[3]	2	[3]
Total Assets	40		48
Liabilities	'		'
Liabilities	-10		-22
Net Total Assets (Liability)	30		26
Net Fair Value [Member] | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-2	[3]	-10	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	-7	[4]	-10	[4]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY	'		'
Assets	'		'
Cash Equivalent	0	[1]	1	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	1	[3]	2	[3]
Total Assets	25		29
Liabilities	'		'
Liabilities	-9		-14
Net Total Assets (Liability)	16		15
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]	'		'
Liabilities	'		'
Derivative Liability	-1	[3]	-2	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]	'		'
Liabilities	'		'
Derivative Liability	($7)	[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 or Level 3), 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.

FAIR_VALUE_MEASUREMENTS_DERIVA3

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Cash Flow Hedges [Abstract]	'
Estimated loss expected to be reclassified to earnings within the next twelve months	$4

FAIR_VALUE_MEASUREMENTS_DERIVA4

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Financial Impact of Energy Contracts) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Increase (Decrease) to Regulatory Assets/Liabilities	($9)	($21)	$2
TUCSON ELECTRIC POWER COMPANY	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Increase (Decrease) to Regulatory Assets/Liabilities	$0	($6)	$2

FAIR_VALUE_MEASUREMENTS_DERIVA5

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Dec. 31, 2013	Dec. 31, 2012
	GWh	GWh
Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	1,583	2,228
Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	33,371,000,000	17,851,000,000
TUCSON ELECTRIC POWER COMPANY | Power Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	779	820
TUCSON ELECTRIC POWER COMPANY | Gas Contracts [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivatives Volumes	9,615,000,000	7,958,000,000

FAIR_VALUE_MEASUREMENTS_DERIVA6

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Quantitative Information Regarding Unobservable Inputs) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	$7	[1]	$7	[1]
Level 3 [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	4	[1]	5	[1]
Derivative Liability	-6		'
Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	1	[2]	'
Derivative Liability	-4	[2]	'
Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	3	[3]	'
Derivative Liability	-2	[3]	'
Minimum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MWh/MMbtu	26.54		'
Minimum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MWh/MMbtu	3.87		'
Gas Volatility	25.05%		'
Maximum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MWh/MMbtu	51.75		'
Maximum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Market price per MWh/MMbtu	4.32		'
Gas Volatility	35.07%		'
TUCSON ELECTRIC POWER COMPANY	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	2	[1]	3	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	1	[1]	2	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	1		'
Derivative Liability	-3	[2]	'
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]	'		'
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]	'		'
Assets	$1		'
[1]	Energy Contracts include gas swap agreements (Level 2), power options (Level 2 or Level 3), 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.
[2]	TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.
[3]	TEP comprises less than $1 million of the option contract assets.

FAIR_VALUE_MEASUREMENTS_DERIVA7

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'
Beginning balance	'	($5)	($10)
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	'	-1	-5
Settlements	'	4	10
Ending balance	'	-2	-5
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	'	-1	-1
Transfered amount out of Level 3	0.5	'	'
TUCSON ELECTRIC POWER COMPANY	'	'	'
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]	'	'	'
Beginning balance	'	0	0
Realized/Unrealized Gains/(Losses) Recorded to:	'	'	'
Net Regulatory Assets/Liabilities - Derivative Instruments	'	-2	1
Settlements	'	0	-1
Ending balance	'	-2	0
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period	'	($1)	$0

FAIR_VALUE_MEASUREMENTS_DERIVA8

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative [Line Items]	'
Fair value of derivative instruments	($21)
Additional collateral if credit-risk contingent features are triggered	21
TUCSON ELECTRIC POWER COMPANY	'
Derivative [Line Items]	'
Fair value of derivative instruments	5
Additional collateral if credit-risk contingent features are triggered	($5)

FAIR_VALUE_MEASUREMENTS_DERIVA9

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Liabilities:	'	'
Long-Term Debt	$1,507,070,000	$1,498,442,000
TUCSON ELECTRIC POWER COMPANY	'	'
Liabilities:	'	'
Long-Term Debt	1,223,070,000	'
Carrying Value [Member] | Level 2 [Member]	'	'
Liabilities:	'	'
Long-Term Debt	1,507,000,000	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	1,223,000,000	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	1,521,000,000	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	1,214,000,000	1,271,000,000
Fair Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY	'	'
Assets:	'	'
TEP Investment in Lease Equity	$25,000,000	$23,000,000

CHANGES_IN_ACCUMULATED_OTHER_C1

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Gains and Losses on Cash Flow Hedges	'	'	'
Tax Benefit	$1,801	'	'
Realized Losses on Cash Flow Hedges, Net of Taxes	-2,752	'	'
Amortization of SERP and Defined Benefit Plans	'	'	'
Prior Service Costs	-1,488	'	'
Tax (Expense) Benefit	572	-608	804
Amortization, Net of Taxes	-916	840	-1,158
Total Reclassification from Other Comprehensive Income for the Period	-3,668	'	'
TUCSON ELECTRIC POWER COMPANY	'	'	'
Gains and Losses on Cash Flow Hedges	'	'	'
Tax Benefit	1,718	'	'
Realized Losses on Cash Flow Hedges, Net of Taxes	-2,624	'	'
Amortization of SERP and Defined Benefit Plans	'	'	'
Prior Service Costs	-1,488	'	'
Tax (Expense) Benefit	572	-608	804
Amortization, Net of Taxes	-916	840	-1,158
Total Reclassification from Other Comprehensive Income for the Period	-3,540	'	'
Interest Rate Contract Long Term Debt [Member]	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-1,377	'	'
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	-1,166	'	'
Interest Rate contract Capital Leases [Member]	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-2,429	'	'
Interest Rate contract Capital Leases [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-2,429	'	'
Commodity Contract [Member]	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-747	'	'
Commodity Contract [Member] | TUCSON ELECTRIC POWER COMPANY	'	'	'
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	($747)	'	'

QUARTERLY_FINANCIAL_DATA_Summa

QUARTERLY FINANCIAL DATA - Summary of Quarterly Financial Data (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating Revenue	$350,161	$437,041	$365,217	$332,141	$348,273	$434,108	$363,998	$315,387	$1,484,560	$1,461,766	$1,478,702
Operating Income	41,033	129,765	60,803	39,895	42,918	106,409	68,065	34,403	271,496	251,795	281,707
Net Income (Loss)	13,525	67,990	34,618	11,345	7,506	50,664	26,273	6,476	127,478	90,919	109,975
Basic EPS	$0.32	$1.63	$0.83	$0.27	$0.18	$1.22	$0.65	$0.17	$3.06	$2.25	$2.98
Diluted EPS	$0.32	$1.62	$0.83	$0.27	$0.18	$1.21	$0.64	$0.17	$3.04	$2.20	$2.75
TUCSON ELECTRIC POWER COMPANY	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating Revenue	273,437	371,239	304,263	247,751	271,353	366,910	299,419	223,978	1,196,690	1,161,660	1,156,386
Operating Income	31,014	123,177	53,433	22,747	30,299	94,079	58,211	17,898	230,371	200,487	229,408
Net Income (Loss)	$4,910	$64,167	$30,787	$1,478	$452	$44,569	$21,910	($1,461)	$101,342	$65,470	$85,334

SCHEDULE_II_Valuation_and_Qual1

SCHEDULE II - Valuation and Qualifying Accounts (Detail) (USD $)

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Allowance for Doubtful Accounts [Member]

Allowance for Doubtful Accounts [Member]

Allowance for Doubtful Accounts [Member]

Other Valuation Allowance [Member]

Other Valuation Allowance [Member]

Other Valuation Allowance [Member]

Other Valuation Allowance [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

TUCSON ELECTRIC POWER COMPANY

Allowance for Doubtful Accounts [Member]

Allowance for Doubtful Accounts [Member]

Allowance for Doubtful Accounts [Member]

Other Valuation Allowance [Member]

Other Valuation Allowance [Member]

Other Valuation Allowance [Member]

Other Valuation Allowance [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beginning Balance

$7

$16

$13

$6

$9

$6

$4

$5

[1]

$14

[1]

$11

[1]

$4

[2]

$8

[2]

$4

[2]

$3

[2]

Additions-Charged to Income

2

4

5

'

'

'

'

2

[1]

3

[1]

4

[1]

'

'

'

'

Deductions

2

13

2

'

'

'

'

2

[1]

12

[1]

1

[1]

'

'

'

'

Ending Balance

$7

$7

$16

$6

$9

$6

$4

$5

[1]

$5

[1]

$14

[1]

$4

[2]

$8

[2]

$4

[2]

$3

[2]

[1]

TEP, UNS Electric, and UNS Gas record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.

[2]

As the Other reserves are not individually significant, additions and deductions need not be disclosed. Principally reserves for sales tax audits, litigation matters, and damages billable to third parties.