10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     .

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification Number
1-13739	UNS ENERGY CORPORATION (An Arizona Corporation) 88 East Broadway Boulevard Tucson, AZ 85701 (520) 571-4000	86-0786732
1-5924	TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) 88 East Broadway Boulevard Tucson, AZ 85701 (520) 571-4000	86-0062700

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

UNS Energy Corporation	Yes  x	No  ¨
Tucson Electric Power Company	Yes  x	No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

UNS Energy Corporation	Yes  x	No  ¨
Tucson Electric Power Company	Yes  x	No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

UNS Energy Corporation	Large Accelerated Filer	x	Accelerated Filer	¨
	Non-accelerated Filer	¨	Smaller Reporting Company	¨

Tucson Electric Power Company	Large Accelerated Filer	¨	Accelerated Filer	¨
	Non-accelerated Filer	x	Smaller Reporting Company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

UNS Energy Corporation	Yes  ¨	No  x
Tucson Electric Power Company	Yes  ¨	No  x

As of July 18, 2014, 41,701,718 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of July 18, 2014, Tucson Electric Power Company had 32,139,434 shares of common stock outstanding, no par value, all of which were held by UNS Energy Corporation.

This combined Form 10-Q is separately filed by UNS Energy Corporation and Tucson Electric Power Company. Information contained in this document relating to Tucson Electric Power Company is filed by UNS Energy Corporation and separately by Tucson Electric Power Company on its own behalf. Tucson Electric Power Company makes no representation as to information relating to UNS Energy Corporation or its subsidiaries, except as it may relate to Tucson Electric Power Company.

ii

Table of Contents

Definitions	iv
PART I
Item 1. Financial Statements
UNS Energy Corporation
Condensed Consolidated Statements of Income	1
Condensed Consolidated Statements of Comprehensive Income	2
Condensed Consolidated Statements of Cash Flows	3
Condensed Consolidated Balance Sheets	4
Condensed Consolidated Statements of Changes in Stockholders’ Equity	6
Tucson Electric Power Company
Condensed Consolidated Statements of Income	7
Condensed Consolidated Statements of Comprehensive Income	8
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Balance Sheets	10
Condensed Consolidated Statements of Changes in Stockholder’s Equity	12
Notes to Condensed Consolidated Financial Statements
Note 1. Nature of Operations and Financial Statement Presentation	13
Note 2. Pending Merger with Fortis	13
Note 3. Regulatory Matters	14
Note 4. Business Segments	15
Note 5. Debt and Capital Lease Obligations	16
Note 6. Commitments, Contingencies, and Environmental Matters	17
Note 7. Planned Purchase of Gas-Fired Generation Facility	21
Note 8. Employee Benefit Plans	21
Note 9. Share-Based Compensation Plans	22
Note 10. UNS Energy Earnings Per Share	23
Note 11. Supplemental Cash Flow Information	24
Note 12. Fair Value Measurements and Derivative Instruments	25
Note 13. Income Taxes	32
Note 14. Reclassifications from Accumulated Other Comprehensive Income by Component	33
Note 15. Recently Issued Accounting Pronouncements	35
Item  2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
UNS Energy Consolidated	36
Tucson Electric Power Company	43
UNS Electric	56
UNS Gas	61
Critical Accounting Policies	65
Safe Harbor for Forward-Looking Statements	65
Item 3. – Quantitative and Qualitative Disclosures about Market Risk	65
Item 4. – Controls and Procedures	66
PART II
Item 1. – Legal Proceedings	67
Item 1A. – Risk Factors	67
Item 5. – Other Information	67
Item 6. – Exhibits	70
Signatures	71
Exhibit Index	72

iii

DEFINITIONS

The abbreviations and acronyms used in the second quarter2014 Form 10-Q are defined below:

2010 TEP Reimbursement Agreement	Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2013 Covenants Agreement	A Lender Rate Mode Covenants Agreement between TEP and the purchaser of $100 million of unsecured tax-exempt bonds that were issued on behalf of TEP in November 2013 and sold in a private placement
ACC	Arizona Corporation Commission
APS	Arizona Public Service Company
BART	Best Available Retrofit Technology
Base O&M	A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business
Base Rates	The portion of TEP’s and UNS Electric’s Retail Rates attributed to generation, transmission, distribution costs, and customer charge; and UNS Gas’ delivery costs and customer charge. Base Rates exclude costs that are passed through to customers for fuel and purchased energy costs
Btu	British thermal unit(s)
Cooling Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DSM	Demand Side Management
ECA	Environmental Compliance Adjustor
Entegra	a subsidiary of Entegra Power Group LLC
FERC	Federal Energy Regulatory Commission
Fortis	Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada
Four Corners	Four Corners Generating Station
GBtu	Billion British thermal units
GWh	Gigawatt-hour(s)
Gila River Unit 3	Unit 3 of the Gila River Generating Station
Heating Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65
kV	Kilo-volt
kWh	Kilowatt-hour(s)
LFCR	Lost Fixed Cost Recovery Mechanism
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation
MMBtu	Million British thermal units
MW	Megawatt(s)
MWh	Megawatt-hour(s)
Navajo	Navajo Generating Station
OATT	Open Access Transmission Tariff
PGA	Purchased Gas Adjustor, a Retail Rate mechanism designed to recover the cost of gas purchased for retail gas customers
PNM	Public Service Company of New Mexico
PPFAC	Purchased Power and Fuel Adjustment Clause
REC	Renewable Energy Credit
Regional Haze Rules	Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
Regulated Utilities	Tucson Electric Power Company (TEP); UNS Electric, Inc. (UNS Electric); and UNS Gas, Inc. (UNS Gas) collectively

iv

RES	Renewable Energy Standard
Retail Rates	Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service
San Juan	San Juan Generating Station
SCR	Selective Catalytic Reduction
SJCC	San Juan Coal Company
SNCR	Selective Non-Catalytic Reduction
Springerville	Springerville Generating Station
Springerville Coal Handling Facilities	Coal handling facilities at Springerville used by all four Springerville units
Springerville Coal Handling Facilities Leases	Leases for coal handling facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities	Facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities Leases	Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1	Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases	Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2	Unit 2 of the Springerville Generating Station
Springerville Unit 3	Unit 3 of the Springerville Generating Station
Springerville Unit 4	Unit 4 of the Springerville Generating Station
SRP	Salt River Project Agricultural Improvement and Power District
Sundt	H. Wilson Sundt Generating Station
Sundt Unit 4	Unit 4 of the H. Wilson Sundt Generating Station
TCA	Transmission Cost Adjustor
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Therm	A unit of heating value equivalent to 100,000 Btus
Tri-State	Tri-State Generation and Transmission Association, Inc.
UED	UniSource Energy Development Company, a wholly-owned subsidiary of UNS Energy Corporation
UES	UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy, and intermediate holding company established to own the operating companies UNS Electric and UNS Gas
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES
UNS Energy	UNS Energy Corporation (formerly known as UniSource Energy Corporation)
UNS Gas	UNS Gas, Inc., a wholly-owned subsidiary of UES

v

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Three Months Ended							Six Months Ended
June 30,							June 30,
2014			2013				2014			2013
(Unaudited)							(Unaudited)
Thousands of Dollars							Thousands of Dollars
(Except Per Share Amounts)							(Except Per Share Amounts)
						Operating Revenues
$	302,975		$	285,419		Electric Retail Sales	$	527,545		$	506,279
33,309			30,654			Electric Wholesale Sales	76,730			65,052
21,911			20,013			Gas Retail Sales	60,481			71,002
28,411			29,131			Other Revenues	55,242			55,025
386,606			365,217			Total Operating Revenues	719,998			697,358
						Operating Expenses
69,418			86,459			Fuel	137,253			168,148
84,060			57,796			Purchased Energy	153,843			121,955
6,142			4,521			Transmission and Other PPFAC Recoverable Costs	12,670			7,707
(12,517		)	2,074			Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(21,437		)	(3,294		)
147,103			150,850			Total Fuel and Purchased Energy	282,329			294,516
91,621			95,143			Operations and Maintenance	185,057			185,043
39,563			36,671			Depreciation	78,644			72,970
6,455			8,119			Amortization	12,631			16,408
14,942			13,631			Taxes Other Than Income Taxes	29,750			27,723
299,684			304,414			Total Operating Expenses	588,411			596,660
86,922			60,803			Operating Income	131,587			100,698
						Other Income (Deductions)
169			19			Interest Income	249			28
2,538			1,734			Other Income	4,680			3,502
(958		)	(807		)	Other Expense	(1,688		)	(1,380		)
624			94			Appreciation in Fair Value of Investments	879			1,133
2,373			1,040			Total Other Income (Deductions)	4,120			3,283
						Interest Expense
19,167			17,700			Long-Term Debt	37,055			35,954
3,925			6,249			Capital Leases	7,846			12,498
307			346			Other Interest Expense	790			(47		)
(1,295		)	(745		)	Interest Capitalized	(2,318		)	(1,420		)
22,104			23,550			Total Interest Expense	43,373			46,985
67,191			38,293			Income Before Income Taxes	92,334			56,996
24,837			3,675			Income Tax Expense	34,505			11,033
$	42,354		$	34,618		Net Income	$	57,829		$	45,963
						Weighted-Average Shares of Common Stock Outstanding (000)
41,781			41,598			Basic	41,759			41,569
42,145			41,921			Diluted	42,115			41,898
						Earnings Per Share
$	1.01		$	0.83		Basic	$	1.38		$	1.11
$	1.01		$	0.83		Diluted	$	1.37		$	1.10
$	0.480		$	0.435		Dividends Declared Per Share	$	0.960		$	0.870

See Notes to Condensed Consolidated Financial Statements.

1

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended					Six Months Ended
June 30,					June 30,
2014		2013			2014		2013
(Unaudited)					(Unaudited)
Thousands of Dollars					Thousands of Dollars
				Comprehensive Income
$	42,354	$	34,618	Net Income	$	57,829	$	45,963
				Other Comprehensive Income
				Net Changes in Fair Value of Cash Flow Hedges:
517		933		net of income tax expense of $335 and $610
				net of income tax expense of $691 and $1,009	1,010		1,544
				Supplemental Executive Retirement Plan (SERP) Benefit Amortization:
25		68		net of income tax expense of $15 and $43
				net of income tax expense of $30 and $85	49		137
542		1,001		Total Other Comprehensive Income, Net of Tax	1,059		1,681
$	42,896	$	35,619	Total Comprehensive Income	$	58,888	$	47,644

See Notes to Condensed Consolidated Financial Statements.

2

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
	2014			2013
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	531,439		$	519,154
Cash Receipts from Electric Wholesale Sales	89,741			82,273
Cash Receipts from Gas Retail Sales	80,348			91,207
Cash Receipts from Operating Springerville Units 3 & 4	47,099			49,974
Cash Receipts from Gas Wholesale Sales	2,287			3,494
Income Tax Refunds Received	472			—
Interest Received	7			516
Other Cash Receipts	22,812			16,914
Purchased Energy Costs Paid	(152,982		)	(135,775		)
Payment of Operations and Maintenance Costs	(138,692		)	(121,272		)
Fuel Costs Paid	(135,128		)	(140,185		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(86,695		)	(90,554		)
Wages Paid, Net of Amounts Capitalized	(72,237		)	(68,004		)
Interest Paid, Net of Amounts Capitalized	(31,446		)	(34,662		)
Capital Lease Interest Paid	(15,888		)	(18,630		)
Other Cash Payments	(3,380		)	(6,798		)
Net Cash Flows—Operating Activities	137,757			147,652
Cash Flows from Investing Activities
Capital Expenditures	(186,037		)	(155,685		)
Return of Investments in Springerville Lease Debt	—			9,104
Other, net	(4,345		)	(3,613		)
Net Cash Flows—Investing Activities	(190,382		)	(150,194		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	151,000			114,000
Repayments of Borrowings Under Revolving Credit Facilities	(129,000		)	(48,000		)
Proceeds from Issuance of Long-Term Debt	149,168			—
Payments of Capital Lease Obligations	(83,204		)	(84,206		)
Common Stock Dividends Paid	(40,034		)	(36,079		)
Payment of Debt Issue/Retirement Costs	(1,641		)	(982		)
Proceeds from Stock Options Exercised	595			—
Other, net	543			3,584
Net Cash Flows—Financing Activities	47,427			(51,683		)
Net Increase (Decrease) in Cash and Cash Equivalents	(5,198		)	(54,225		)
Cash and Cash Equivalents, Beginning of Year	74,878			123,918
Cash and Cash Equivalents, End of Period	$	69,680		$	69,693

See Note 11 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

3

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2014			2013
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	5,392,666		$	5,192,122
Utility Plant Under Capital Leases	747,158			637,957
Construction Work in Progress	186,249			201,959
Total Utility Plant	6,326,073			6,032,038
Less Accumulated Depreciation and Amortization	(2,078,626		)	(1,982,524		)
Less Accumulated Amortization of Capital Lease Assets	(525,327		)	(514,677		)
Total Utility Plant—Net	3,722,120			3,534,837
Investments and Other Property
Investments in Lease Equity	36,122			36,194
Other	35,551			34,971
Total Investments and Other Property	71,673			71,165
Current Assets
Cash and Cash Equivalents	69,680			74,878
Accounts Receivable—Customer	114,276			104,596
Unbilled Accounts Receivable	67,637			52,403
Allowance for Doubtful Accounts	(7,001		)	(6,833		)
Materials and Supplies	92,771			88,085
Deferred Income Taxes—Current	86,401			66,906
Regulatory Assets—Current	69,322			52,763
Fuel Inventory	44,044			44,317
Derivative Instruments	9,850			5,629
Other	17,453			15,354
Total Current Assets	564,433			498,098
Regulatory and Other Assets
Regulatory Assets—Noncurrent	162,263			150,584
Derivative Instruments	1,528			1,180
Other Assets	26,575			24,430
Total Regulatory and Other Assets	190,366			176,194
Total Assets	$	4,548,592		$	4,280,294

See Notes to Condensed Consolidated Financial Statements.

(Continued)

4

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2014		2013
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,149,578	$	1,130,784
Capital Lease Obligations	69,938		131,370
Long-Term Debt	1,677,323		1,507,070
Total Capitalization	2,896,839		2,769,224
Current Liabilities
Current Obligations Under Capital Leases	272,939		186,056
Borrowings Under Revolving Credit Facilities	23,000		22,000
Accounts Payable—Trade	104,720		117,503
Regulatory Liabilities—Current	54,384		53,935
Accrued Taxes Other than Income Taxes	47,601		43,880
Customer Deposits	28,066		30,671
Accrued Employee Expenses	23,202		28,148
Accrued Interest	29,637		27,786
Derivative Instruments	6,435		7,534
Other	22,536		17,775
Total Current Liabilities	612,520		535,288
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	528,636		488,887
Regulatory Liabilities—Noncurrent	326,388		302,482
Pension and Other Retiree Benefits	90,984		90,923
Derivative Instruments	5,976		7,100
Other	87,249		86,390
Total Deferred Credits and Other Liabilities	1,039,233		975,782
Commitments, Contingencies, and Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$	4,548,592	$	4,280,294

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

5

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Shares Outstanding *	Common Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	(Unaudited)
	Thousands of Shares	Thousands of Dollars
Balances at December 31, 2013	41,538	$	889,301		$	247,532		$	(6,049	)	$	1,130,784
Net Income					57,829						57,829
Other Comprehensive Income, net of tax								1,059			1,059
Dividends Declared					(40,372		)				(40,372		)
Shares Issued for Stock Options	20	594									594
Shares Issued under Performance Share Awards	101	—									—
Share-based Compensation		(316		)							(316		)
Balances at June 30, 2014	41,659	$	889,579		$	264,989		$	(4,990	)	$	1,149,578

* UNS Energy has 75 million authorized shares of Common Stock.

See Notes to Condensed Consolidated Financial Statements.

6

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Three Months Ended							Six Months Ended
June 30,							June 30,
2014			2013				2014			2013
(Unaudited)							(Unaudited)
Thousands of Dollars							Thousands of Dollars
						Operating Revenues
$	257,790		$	243,635		Electric Retail Sales	$	443,805		$	428,515
32,555			29,542			Electric Wholesale Sales	74,639			63,940
31,273			31,086			Other Revenues	58,687			59,559
321,618			304,263			Total Operating Revenues	577,131			552,014
						Operating Expenses
68,334			84,553			Fuel	135,964			165,351
52,906			28,410			Purchased Power	75,521			47,338
3,552			1,730			Transmission and Other PPFAC Recoverable Costs	7,461			2,595
(13,061		)	5,274			Increase (Decrease) to Reflect PPFAC Recovery Treatment	(14,791		)	2,914
111,731			119,967			Total Fuel and Purchased Energy	204,155			218,198
79,772			82,011			Operations and Maintenance	161,117			159,835
31,080			28,861			Depreciation	61,891			57,418
7,377			9,052			Amortization	14,476			18,275
12,005			10,939			Taxes Other Than Income Taxes	23,840			22,108
241,965			250,830			Total Operating Expenses	465,479			475,834
79,653			53,433			Operating Income	111,652			76,180
						Other Income (Deductions)
165			12			Interest Income	174			8
2,187			1,270			Other Income	4,099			2,438
(2,694		)	(2,472		)	Other Expense	(4,809		)	(4,717		)
624			94			Appreciation in Fair Value of Investments	879			1,133
282			(1,096		)	Total Other Income (Deductions)	343			(1,138		)
						Interest Expense
15,507			13,991			Long-Term Debt	29,747			28,564
3,925			6,249			Capital Leases	7,846			12,498
140			192			Other Interest Expense	453			(168		)
(1,104		)	(534		)	Interest Capitalized	(2,028		)	(1,027		)
18,468			19,898			Total Interest Expense	36,018			39,867
61,467			32,439			Income Before Income Taxes	75,977			35,175
22,742			1,652			Income Tax Expense	28,080			2,909
$	38,725		$	30,787		Net Income	$	47,897		$	32,266

See Notes to Condensed Consolidated Financial Statements.

7

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended					Six Months Ended
June 30,					June 30,
2014		2013			2014		2013
(Unaudited)					(Unaudited)
Thousands of Dollars					Thousands of Dollars
				Comprehensive Income
$	38,725	$	30,787	Net Income	$	47,897	$	32,266
				Other Comprehensive Income
				Net Changes in Fair Value of Cash Flow Hedges:
494		878		net of income tax expense of $321 and $574
				net of income tax expense of $667 and $952	975		1,456
				SERP Benefit Amortization:
25		68		net of income tax expense of $15 and $43
				net of income tax expense of $30 and $85	49		137
519		946		Total Other Comprehensive Income, Net of Tax	1,024		1,593
$	39,244	$	31,733	Total Comprehensive Income	$	48,921	$	33,859

See Notes to Condensed Consolidated Financial Statements.

8

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
	2014			2013
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	444,624		$	435,779
Cash Receipts from Electric Wholesale Sales	86,087			75,803
Cash Receipts from Operating Springerville Units 3 & 4	47,099			49,974
Reimbursement of Affiliate Charges	13,633			12,695
Cash Receipts from Gas Wholesale Sales	46			3,145
Income Tax Refunds Received	9			—
Interest Received	5			509
Other Cash Receipts	19,580			13,320
Payment of Operations and Maintenance Costs	(134,606		)	(117,133		)
Fuel Costs Paid	(134,374		)	(139,596		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(66,588		)	(68,574		)
Wages Paid, Net of Amounts Capitalized	(60,845		)	(57,483		)
Purchased Power Costs Paid	(59,088		)	(40,949		)
Interest Paid, Net of Amounts Capitalized	(24,588		)	(27,590		)
Capital Lease Interest Paid	(15,888		)	(18,630		)
Other Cash Payments	(2,064		)	(5,728		)
Net Cash Flows—Operating Activities	113,042			115,542
Cash Flows from Investing Activities
Capital Expenditures	(157,161		)	(118,210		)
Return of Investments in Springerville Lease Debt	—			9,104
Other, net	(3,460		)	(3,470		)
Net Cash Flows—Investing Activities	(160,621		)	(112,576		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	105,000			78,000
Repayments of Borrowings Under Revolving Credit Facility	(105,000		)	(48,000		)
Proceeds from Issuance of Long-Term Debt	149,168			—
Payments of Capital Lease Obligations	(83,204		)	(84,206		)
Payment of Debt Issue/Retirement Costs	(1,641		)	(982		)
Other, net	656			596
Net Cash Flows—Financing Activities	64,979			(54,592		)
Net Increase (Decrease) in Cash and Cash Equivalents	17,400			(51,626		)
Cash and Cash Equivalents, Beginning of Year	25,335			79,743
Cash and Cash Equivalents, End of Period	$	42,735		$	28,117

See Note 11 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

9

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2014			2013
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	4,644,399		$	4,467,667
Utility Plant Under Capital Leases	747,158			637,957
Construction Work in Progress	169,459			180,485
Total Utility Plant	5,561,016			5,286,109
Less Accumulated Depreciation and Amortization	(1,913,655		)	(1,826,977		)
Less Accumulated Amortization of Capital Lease Assets	(525,327		)	(514,677		)
Total Utility Plant—Net	3,122,034			2,944,455
Investments and Other Property
Investments in Lease Equity	36,122			36,194
Other	34,192			33,488
Total Investments and Other Property	70,314			69,682
Current Assets
Cash and Cash Equivalents	42,735			25,335
Accounts Receivable—Customer	96,513			80,211
Unbilled Accounts Receivable	56,252			34,369
Allowance for Doubtful Accounts	(4,977		)	(4,825		)
Accounts Receivable—Due from Affiliates	2,818			6,064
Materials and Supplies	79,409			75,200
Deferred Income Taxes—Current	91,585			70,722
Fuel Inventory	43,754			44,027
Regulatory Assets—Current	59,091			42,555
Derivative Instruments	4,289			2,137
Other	14,864			12,923
Total Current Assets	486,333			388,718
Regulatory and Other Assets
Regulatory Assets—Noncurrent	152,259			141,030
Derivative Instruments	493			167
Other Assets	21,093			19,233
Total Regulatory and Other Assets	173,845			160,430
Total Assets	$	3,852,526		$	3,563,285

See Notes to Condensed Consolidated Financial Statements.

(Continued)

10

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2014		2013
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	974,844	$	925,923
Capital Lease Obligations	69,938		131,370
Long-Term Debt	1,372,323		1,223,070
Total Capitalization	2,417,105		2,280,363
Current Liabilities
Current Obligations Under Capital Leases	272,939		186,056
Accounts Payable—Trade	89,162		88,556
Accounts Payable—Due to Affiliates	5,282		9,153
Accrued Taxes Other than Income Taxes	39,732		34,485
Accrued Employee Expenses	19,726		24,454
Regulatory Liabilities—Current	28,075		23,701
Accrued Interest	24,651		22,785
Customer Deposits	20,906		21,354
Derivative Instruments	4,261		5,531
Other	13,641		9,244
Total Current Liabilities	518,375		425,319
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	464,983		428,103
Regulatory Liabilities—Noncurrent	283,475		263,270
Pension and Other Retiree Benefits	84,724		84,936
Derivative Instruments	4,907		5,161
Other	78,957		76,133
Total Deferred Credits and Other Liabilities	917,046		857,603
Commitments, Contingencies, and Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$	3,852,526	$	3,563,285

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

11

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY

	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	(Unaudited)
	Thousands of Dollars
Balances at December 31, 2013	$	888,971	$	(6,357	)	$	49,185	$	(5,876	)	$	925,923
Net Income						47,897					47,897
Other Comprehensive Income, net of tax								1,024			1,024
Balances at June 30, 2014	$	888,971	$	(6,357	)	$	97,082	$	(4,852	)	$	974,844

See Notes to Condensed Consolidated Financial Statements.

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

UNS Energy Corporation (UNS Energy) is a holding company that conducts its business through three regulated public utilities: Tucson Electric Power Company (TEP); UNS Electric, Inc. (UNS Electric); and UNS Gas, Inc. (UNS Gas) (collectively Regulated Utilities). References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.

We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K.

The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results. UNS Energy and TEP reclassified certain amounts in the financial statements to conform to current year presentation.

REVISION OF PRIOR PERIOD BALANCE SHEETS

UNS Energy and TEP revised their December 31, 2013 balance sheets to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2014, we adopted accounting guidance that:

• requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.

• impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.

NOTE 2. PENDING MERGER WITH FORTIS

On December 11, 2013, UNS Energy announced that it had entered into an Agreement and Plan of Merger (Merger), subject to shareholder and required regulatory approvals, to be acquired by Fortis Inc. (Fortis) for $60.25 per share of Common Stock in cash. Following the Merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Boards of Directors of each of UNS Energy and Fortis have approved the Merger.

The following additional approvals have been received:

• In March 2014, UNS Energy's shareholders approved the Merger;

• In April 2014, the Federal Energy Regulatory Commission (FERC) approved the Merger;

• In May 2014, the Committee on Foreign Investment in the United States concluded its review determining there are no unresolved national security concerns with respect to the Merger;

• In June 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

• In July 2014, the Federal Communications Commission approved UNS Energy’s FCC license transfer of control applications with respect to the Merger.

The final regulatory approval necessary to complete the Merger is approval by the Arizona Corporation Commission (ACC). In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a settlement (Settlement) in which the parties agree that the Merger is in the public interest and recommend approval by the ACC, subject to certain conditions. Those conditions include, but are not limited to, the following:

• UNS Energy shall provide credits on the Regulated Utilities retail customers' bills totaling $30 million over five years; $10 million in year one and $5 million annually in years two through five. The monthly bill credits will be applied each year from October through March. If the Merger closes by the end of September 2014, the bill credits will commence on October 1, 2014;

• UNS Energy and the Regulated Utilities will adopt certain ring-fencing and corporate governance provisions;

• Dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014; and

• Fortis shall make an equity investment totaling $220 million through UNS Energy into the Regulated Utilities following closing of the Merger. However, if the Merger closes after September 30, 2014, the equity investment may be made into UNS Energy to retire debt.

The Settlement is subject to the review and approval of the ACC, which could approve, reject, or require modifications to the Settlement as a condition of approval of the Merger. Hearings before an ACC administrative law judge on the Settlement concluded on June 17, 2014. The Settlement requests that the ACC issue an order approving the Settlement no later than September 18, 2014.

The completion of the Merger is also subject to the absence of any injunction, order, or other law prohibiting the Merger.

If the Merger is approved by the ACC in September 2014 as requested by the parties to the Settlement Agreement, we expect the Merger to close by the end of September 2014. Upon completion of the Merger, UNS Energy expects to record approximately $19 million of merger-related expenses including investment banker fees, legal fees, and accelerated expenses for certain share-based compensation awards. TEP would record approximately $15 million as its allocated share of these merger-related expenses. See Note 9.

NOTE 3. REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of the Regulated Utilities.

The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales. The Merger with Fortis is subject to approval by the ACC. See Note 2. Additionally, the purchase of Gila River Generating Station Unit 3 (Gila River Unit 3) remains subject to FERC approval. See Note 7.

COST RECOVERY MECHANISMS

TEP Purchased Power and Fuel Adjustment Clause

In April 2014, the ACC approved a Purchased Power and Fuel Adjustment Clause (PPFAC) rate for TEP of 0.1 cents per kWh for the period May through September 2014 and 0.5 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was a credit of 0.14 cents per kWh for the period July 2013 through April 2014.

In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. At June 30, 2014, TEP has received

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.

TEP Environmental Compliance Adjustor

The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP expects to recognize ECA revenues of less than $1 million in 2014.

UNS Electric Transmission Cost Adjustor

The 2013 UNS Electric Rate Order provided a Transmission Cost Adjustor (TCA) that allows more timely recovery of transmission costs associated with serving retail customers. The TCA rate is adjusted annually based on information filed with the ACC each May. The TCA rate of 0.114 cents per kWh became effective in June 2014.

UNS Gas Purchased Gas Adjustor

In November of 2013, a Purchased Gas Adjustor (PGA) credit of 10 cents per therm became effective for UNS Gas. The credit expired in April 2014.

Energy Efficiency Standards

The Regulated Utilities are required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as a performance incentive. In the first half of 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Sales in the UNS Energy and TEP income statements.

Lost Fixed Cost Recovery Mechanism

The Lost Fixed Cost Recovery (LFCR) mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved energy efficiency programs and distributed generation targets. During separate rate case proceedings in 2013, the ACC authorized LFCR mechanisms for TEP and UNS Electric, subject to a year-over-year cap of 1% of each company’s respective total retail revenues.

TEP and UNS Electric filed their first LFCR reports with the ACC in May 2014. TEP requested recovery of approximately $5 million and UNS Electric requested recovery of approximately $1 million. The LFCR rates are expected to go into effect in August 2014 for TEP and in September 2014 for UNS Electric.

TEP and UNS Electric recorded LFCR revenues of $6 million and $2 million, respectively, in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. We recognize LFCR revenue when verifiable regardless of when the lost retail kWh sales occur. LFCR revenue is included in Electric Retail Sales in the income statements.

NOTE 4. 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

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We disclose selected financial data for our reportable segments in the following tables:

	Reportable Segments
	TEP		UNS Electric		UNS Gas		Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
Three Months Ended June 30, 2014
Operating Revenues-External	$	318	$	47	$	22	$	—		$	—		$	387
Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
Income Before Income Taxes	61		6		—		—			—			67
Net Income	39		4		—		(1		)	—			42
Three Months Ended June 30, 2013
Operating Revenues-External	$	300	$	44	$	21	$	—		$	—		$	365
Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
Income Before Income Taxes	32		6		—		—			—			38
Net Income	31		4		—		—			—			35

	Reportable Segments
	TEP		UNS Electric		UNS Gas		Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
Six Months Ended June 30, 2014
Operating Revenues-External	$	569	87		64		$	—		$	—		$	720
Operating Revenues-Intersegment (1)	8		1		1		8			(18		)	—
Income Before Income Taxes	76		9		8		(1		)	—			92
Net Income	48		6		5		(1		)	—			58
Six Months Ended June 30, 2013
Operating Revenues-External	$	543	$	80	$	73	$	1		$	—		$	697
Operating Revenues-Intersegment (1)	9		1		1		8			(19		)	—
Income Before Income Taxes	35		9		13		—			—			57
Net Income	32		6		8		—			—			46

⁽¹⁾  Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

⁽²⁾  Other includes the UNS Energy and UES holding companies, Millennium, and UED.

NOTE 5. DEBT AND CAPITAL LEASE OBLIGATIONS

We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2013 Annual Report on Form 10-K.

TEP SPRINGERVILLE COAL HANDLING FACILITIES CAPITAL LEASE PURCHASE COMMITMENT

In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, TEP recorded, in April of 2014, an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP previously agreed with Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at June 30, 2014.

2014 TEP UNSECURED NOTES ISSUED

In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may call the debt prior to September 15, 2043, with a make-whole premium plus accrued interest. After September 15, 2043, TEP may call the debt at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the revolving credit facility, with the remaining proceeds to be applied to general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.

TEP CREDIT AGREEMENT

The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility and an $82 million LOC facility to support tax-exempt bonds. As of June 30, 2014, there is $184 million available under the revolving credit facility. The TEP Credit Agreement expires in November 2016. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.

TEP provided, in the second quarter of 2014, a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 7.

COVENANT COMPLIANCE

At June 30, 2014, we were in compliance with the terms of our loan and credit agreements.

NOTE 6. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS

UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas. In addition to those reported in our 2013 Annual Report on Form 10-K, UNS Energy entered into the following long-term commitments through June 30, 2014:

	UNS Energy Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, including Transportation	$	—	$	9	$	9	$	9	$	8	$	8	$	43
Purchased Power	—		23		—		—		—		—		23
Capital Lease Obligations(1)	—		120		—		—		—		—		120
Total Purchase Commitments	$	—	$	152	$	9	$	9	$	8	$	8	$	186

TEP entered into the following long-term commitments:

	TEP Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	—	$	8	$	8	$	8	$	8	$	8	$	40
Purchased Power	—		15		—		—		—		—		15
Capital Lease Obligations(1)	—		120		—		—		—		—		120
Total Purchase Commitments	$	—	$	143	$	8	$	8	$	8	$	8	$	175

⁽¹⁾  In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS ENERGY CONTINGENCIES

In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a Settlement in which the Regulated Utilities agreed, contingent upon completion of the Merger, to provide credits on retail customers' bills totaling $30 million over five years. See Note 2.

TEP CONTINGENCIES

Planned Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.

Claim Related to San Juan Generating Station

San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The joint participants have agreed to have the matter stayed until August 2014 in furtherance of settlement talks.

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.

In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. The New Mexico Taxation and Revenue Department and APS started settlement negotiations in July 2014. TEP cannot predict the outcome or timing of resolution of this claim.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $20 million at June 30, 2014 and $18 million at December 31, 2013.

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows us to pass through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Discontinued Transmission Project

TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. TEP and UNS Electric plan to keep the path approved in the line siting matter in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery.

Performance Guarantees

The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. As of June 30, 2014, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements expire in 2016 through 2046.

UNS ELECTRIC CONTINGENCIES

Planned Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.

ENVIRONMENTAL MATTERS

Environmental Regulation

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.

Hazardous Air Pollutant Requirements

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATS) rules, additional emission control equipment will be required by April 2015. TEP has received an extension until April 2016 to comply with the MATS rules at Springerville. The operator of Navajo has also received an extension until April 2016. TEP's share of the estimated costs to comply with the MATS rules include the following:

Estimated Mercury Emissions Control Costs:	Navajo		Four Corners		Springerville(1)
	Millions of Dollars
Capital Expenditures	$	1	$	1	$	5
Annual O&M Expenses	1		1		1

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

⁽¹⁾ Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

TEP expects Sundt and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules.

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.

In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the BART rules apply to plants built prior to Springerville. TEP cannot predict the ultimate outcome of these matters.

TEP's estimated costs involved in meeting these rules are:

Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital Expenditures	$	42	$	35	$	35	$	12
Annual O&M Expenses	1		1		2		5-6

⁽¹⁾ The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾ The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

⁽³⁾ In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾ In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 7. PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY

In December 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to FERC approval and other closing conditions.

In December 2013, UNS Electric filed an application for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3. The application is still pending before the ACC.

In June 2014, TEP provided a letter of credit (LOC) for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. The seller is entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the purchase agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled.

NOTE 8. EMPLOYEE BENEFIT PLANS

UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:

	Pension Benefits						Other Retiree Benefits
	Three Months Ended June 30,
	2014			2013			2014		2013
	Millions of Dollars
Service Cost	$	2		$	3		$	1	$	1
Interest Cost	5			4			—		1
Expected Return on Plan Assets	(5		)	(5		)	—		—
Actuarial Loss Amortization	1			2			—		—
Net Periodic Benefit Cost	$	3		$	4		$	1	$	2

	Pension Benefits						Other Retiree Benefits
	Six Months Ended June 30,
	2014			2013			2014		2013
	Millions of Dollars
Service Cost	$	5		$	6		$	2	$	2
Interest Cost	9			8			1		1
Expected Return on Plan Assets	(11		)	(10		)	—		—
Actuarial Loss Amortization	2			4			—		—
Net Periodic Benefit Cost	$	5		$	8		$	3	$	3

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 9. SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS

In May 2014, the UNS Energy Compensation Committee (Compensation Committee) granted 7,486 restricted stock units to non-employee directors at a grant date fair value, based on the grant date closing share price, of $60.11 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. We issue UNS Energy Common Stock (Common Stock) for the vested restricted stock units at the time elected by each of the non-employee directors based on certain eligibility requirements. These restricted stock units accrue dividend equivalents during and subsequent to the vesting period, which are distributed in shares of Common Stock at the same time as the related restricted stock units.

In February 2014, the Compensation Committee granted 16,910 restricted stock units to certain management employees at a grant date fair value, based on the grant date closing share price, of $60.39 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.

PERFORMANCE SHARES

In February 2014, the Compensation Committee granted 33,820 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $57.47 per share. Those awards will be paid out in Common Stock based on UNS Energy’s compound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period ended December 31, 2016. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date closing share price, of $60.39 per share and will be paid out in Common Stock based on cumulative net income for the three-year performance period ended December 31, 2016. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.

The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded share-based compensation expense of less than $1 million for the three months ended June 30, 2014 and June 30, 2013. For the six months ended June 30, 2014, UNS Energy recorded share-based compensation expense of $2 million, $1 million of which related to TEP. For the six months ended June 30, 2013, UNS Energy and TEP recorded share-based compensation expense of $1 million.

At June 30, 2014, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, of which $4 million are allocable to TEP, which will be recorded as compensation expense over the remaining vesting periods through February 2017. The completion of the Merger would result in accelerated vesting and expense recognition for these awards. See Note 2. At June 30, 2014, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 10. UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options or share-based compensation awards were exercised or converted into Common Stock. We excluded anti-dilutive contingently issuable shares from the calculation of diluted EPS.

The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Thousands of Dollars
Numerator: Net Income	$	42,354	$	34,618	$	57,829	$	45,963
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,659		41,427		41,639		41,404
Fully Vested Deferred Stock Units	122		171		120		165
Total Weighted Average Common Stock Outstanding — Basic	41,781		41,598		41,759		41,569
Effect of Dilutive Securities:
Options and Stock Issuable Under Share-Based Compensation Plans	364		323		356		329
Total Weighted Average Common Stock Outstanding — Diluted	42,145		41,921		42,115		41,898

For the six months ended June 30, 2013, we excluded 12,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION

A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:

	UNS Energy
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Net Income	$	57,829		$	45,963
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	78,644			72,970
Amortization Expense	12,631			16,408
Depreciation and Amortization Recorded to Fuel and O&M Expense	3,977			3,516
Amortization of Deferred Debt-Related Costs included in Interest Expense	1,584			1,515
Provision for Retail Customer Bad Debts	1,194			936
Use of Renewable Energy Credits for Compliance	11,313			8,106
Deferred Income Taxes	36,320			36,644
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11,039		)
Pension and Retiree Expense	7,884			11,391
Pension and Retiree Funding	(5,974		)	(8,924		)
Share-Based Compensation Expense	1,859			1,390
Allowance for Equity Funds Used During Construction	(4,038		)	(2,463		)
LFCR Revenue	(7,654		)	—
Decrease to Reflect PPFAC/PGA Recovery	(21,437		)	(3,294		)
PPFAC Reduction - 2013 TEP Rate Order	—			3,000
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(22,766		)	(20,706		)
Materials and Fuel Inventory	(4,413		)	8,777
Accounts Payable	(5,875		)	(9,576		)
Income Taxes	(88		)	(15,980		)
Interest Accrued	1,305			(6,885		)
Taxes Other Than Income Taxes	3,721			490
Other	(8,259		)	15,413
Net Cash Flows – Operating Activities	$	137,757		$	147,652

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	TEP
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Net Income	$	47,897		$	32,266
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	61,891			57,418
Amortization Expense	14,476			18,275
Depreciation and Amortization Recorded to Fuel and O&M Expense	3,406			2,987
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,285			1,216
Provision for Retail Customer Bad Debts	833			711
Use of Renewable Energy Credits for Compliance	9,884			7,414
Deferred Income Taxes	29,641			24,883
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(10,751		)
Pension and Retiree Expense	6,824			9,939
Pension and Retiree Funding	(5,522		)	(8,493		)
Share-Based Compensation Expense	1,496			1,108
Allowance for Equity Funds Used During Construction	(3,524		)	(1,763		)
LFCR Revenue	(6,121		)	—
Increase (Decrease) to Reflect PPFAC Recovery	(14,791		)	2,914
PPFAC Reduction - 2013 TEP Rate Order	—			3,000
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(35,498		)	(30,452		)
Materials and Fuel Inventory	(3,936		)	8,923
Accounts Payable	6,019			(11		)
Income Taxes	(6		)	(10,798		)
Interest Accrued	1,320			(6,886		)
Taxes Other Than Income Taxes	5,247			2,295
Other	(7,779		)	11,347
Net Cash Flows – Operating Activities	$	113,042		$	115,542

NON-CASH TRANSACTIONS

In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase lease interests in April 2015. See Note 5.

In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction.

NOTE 12. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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
	June 30, 2014
	Millions of Dollars
Assets
Cash Equivalents(1)	$	13		$	13	$	—		$	—		$	—		$	13
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	23			—		23			—			—			23
Energy Contracts - Regulatory Recovery(3)	11			—		5			6			(3		)	8
Total Assets	49			15		28			6			(3		)	46
Liabilities
Energy Contracts - Regulatory Recovery(3)	(5		)	—		(1		)	(4		)	3			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(6		)	—		(6		)	—			—			(6		)
Total Liabilities	(12		)	—		(7		)	(5		)	3			(9		)
Net Total Assets (Liabilities)	$	37		$	15	$	21		$	1		$	—		$	37

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	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

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2014
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	23			—		23			—			—			23
Energy Contracts - Regulatory Recovery(3)	5			—		2			3			(2		)	3
Total Assets	30			2		25			3			(2		)	28
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(1		)	(2		)	2			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(6		)	—		(6		)	—			—			(6		)
Total Liabilities	(10		)	—		(7		)	(3		)	2			(8		)
Net Total Assets (Liabilities)	$	20		$	2	$	18		$	—		$	—		$	20

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	2			—		1			1			(1		)	1
Total Assets	26			2		23			1			(1		)	25
Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)	—		—			(2		)	1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(10		)	—		(7		)	(3		)	1			(9		)
Net Total Assets (Liabilities)	$	16		$	2	$	16		$	(2	)	$	—		$	16

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

⁽³⁾  Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.

(4) Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DERIVATIVE INSTRUMENTS

We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA.

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.

We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. In the first half of 2013, we also used this pricing model to value our power options.

We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.

Our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our price curves monthly.

Cash Flow Hedges

We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 14. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million for UNS Energy and TEP.

Financial Impact of Energy Contracts

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:

	UNS Energy					TEP
	Three Months Ended June 30,
	2014		2013			2014		2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	1	$	(9	)	$	2	$	(3	)

	UNS Energy				TEP
	Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	5	$	—	$	2	$	(1	)

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At June 30, 2014, UNS Energy and TEP have energy contracts that will settle through the second quarter of 2017.

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	June 30, 2014	December 31, 2013	June 30, 2014	December 31, 2013
Power Contracts GWh	1,933	1,583	976	779
Gas Contracts GBtu	63,546	33,371	27,176	9,615

Level 3 Fair Value Measurements

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:

		Fair Value at
		June 30, 2014						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	4	$	(4	)	Market price per MWh	$	23.90		-	$	57.90
Option Contracts(2)	Option model	2		(1		)	Market price per MMbtu	$	3.87		-	$	4.57
							Gas volatility	21.01		%	-	32.10		%
Level 3 Energy Contracts		$	6	$	(5	)
		Fair Value at
		December 31, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(3)	Market approach	$	1	$	(4	)	Market price per MWh	$	26.54		-	$	51.75
Option Contracts(4)	Option model	3		(2		)	Market price per MMbtu	$	3.87		-	$	4.32
							Gas volatility	25.05		%	-	35.07		%
Level 3 Energy Contracts		$	4	$	(6	)

⁽¹⁾  TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.

⁽²⁾  TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.

⁽³⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities at December 31, 2013.

⁽⁴⁾  TEP comprises less than $1 million of the option contract assets at December 31, 2013.

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC or PGA mechanisms and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	UNS Energy			TEP
	Three Months Ended June 30, 2014
	Millions of Dollars
Balances at March 31, 2014	$	—		$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	3			2
Settlements	(2		)	—
Balances at June 30, 2014	$	1		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	3		$	3

	UNS Energy			TEP
	Six Months Ended June 30, 2014
	Millions of Dollars
Balances at December 31, 2013	$	(2	)	$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	5			1
Settlements	(2		)	1
Balances at June 30, 2014	$	1		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	2		$	1

	UNS Energy			TEP
	Three Months Ended June 30, 2013
	Millions of Dollars
Balances at March 31, 2013	$	(3	)	$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	—
Settlements	—			—
Balances at June 30, 2013	$	(5	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(4	)	$	—

	UNS Energy			TEP
	Six Months Ended June 30, 2013
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	(1		)
Settlements	2			—
Balances at June 30, 2013	$	(5	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(3	)	$	(1	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to the Regulated Utilities; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.

Material adverse changes could trigger credit risk-related contingent features. At June 30, 2014, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $25 million for UNS Energy and $19 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $25 million for UNS Energy and $19 million for TEP.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:

• The carrying amounts of our current maturities of long-term debt and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.

• For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.

• For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:

		June 30, 2014				December 31, 2013
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Equity	Level 3	$	36	$	25	$	36	$	25
Liabilities:
Long-Term Debt
UNS Energy	Level 2	$	1,677	$	1,771	$	1,507	$	1,521
TEP	Level 2	1,372		1,435		1,223		1,214

31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 13. INCOME TAXES

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:

	UNS Energy						TEP
	Three Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	24		$	14		$	22		$	12
State Income Tax Expense, Net of Federal Deduction	3			2			3			2
Federal/State Tax Credits	(2		)	—			(2		)	—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
Other	—			(1		)	—			(1		)
Total Federal and State Income Tax Expense	$	25		$	4		$	23		$	2

	UNS Energy						TEP
	Six Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	32		$	20		$	27		$	12
State Income Tax Expense, Net of Federal Deduction	4			3			3			2
Federal/State Tax Credits	(2		)	—			(2		)	—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
Other	1			(1		)	—			—
Total Federal and State Income Tax Expense	$	35		$	11		$	28		$	3

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 14. RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:

	UNS Energy
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Three Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(349	)	$	(346	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	430			451
Realized Losses on Cash Flow Hedges, Net of Taxes	(664		)	(690		)
Amortization of SERP
Prior Service Cost and Net Loss	(40		)	(111		)	Operations and Maintenance
Tax Benefit	15			43
Amortization, Net of Taxes	(25		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(689	)	$	(758	)

	UNS Energy
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(702	)	$	(676	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	734			820
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,309		)	(1,255		)
Amortization of SERP
Prior Service Cost and Net Loss	(79		)	(222		)	Operations and Maintenance
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,358	)	$	(1,392	)

33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	TEP
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Three Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(293	)	$	(293	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	408			429
Realized Losses on Cash Flow Hedges, Net of Taxes	(630		)	(659		)
Amortization of SERP
Prior Service Cost and Net Loss	(40		)	(111		)	Other Expense
Tax Benefit	15			43
Amortization, Net of Taxes	(25		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(655	)	$	(727	)

	TEP
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(591	)	$	(575	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	692			781
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,240		)	(1,193		)
Amortization of SERP
Prior Service Cost and Net Loss	(79		)	(222		)	Other Expense
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,289	)	$	(1,330	)

34

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 15. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In April 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.

In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.

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ITEM 2. – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for UNS Energy and its three primary business segments. It includes the following:

• outlook and strategies;

• operating results during the second quarter and first six months of 2014 compared with the same periods of 2013;

• factors affecting our results and outlook;

• liquidity, capital needs, capital resources, and contractual obligations;

• dividends; and

• critical accounting estimates.

UNS ENERGY CORPORATION

OVERVIEW OF CONSOLIDATED BUSINESS

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 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 85% of UNS Energy’s total assets at June 30, 2014. TEP generates, transmits and distributes electricity to approximately 414,000 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 and Springerville Unit 4 on behalf of SRP.

UES holds the common stock of two regulated utilities, UNS Electric and 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 June 30, 2014.

References in this report to “we” and “our” are to UNS Energy and its subsidiaries, collectively.

OUTLOOK AND STRATEGIES

Agreement and Plan of Merger

In December 2013, UNS Energy entered into an Agreement and Plan of Merger (Merger) with Fortis Inc. (Fortis). The Boards of Directors of each of UNS Energy and Fortis have approved the Merger. At the completion of the Merger, each outstanding share of UNS Energy Common Stock will be converted into the right to receive $60.25 in cash and UNS Energy will become a wholly-owned subsidiary of Fortis.

Approvals Received

The following approvals have been received:

• In March 2014, UNS Energy's shareholders approved the Merger;

• In April 2014, the FERC approved the Merger;

36

• In May 2014, the Committee on Foreign Investment in the United States concluded its review determining there are no unresolved national security concerns with respect to the Merger;

• In June 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and

• In July 2014, the Federal Communications Commission approved UNS Energy’s FCC license transfer of control applications with respect to the Merger.

Pending ACC Approval

The final regulatory approval necessary to complete the Merger is approval by the ACC. In January 2014, UNS Energy and Fortis filed an application and supporting testimony with the ACC requesting approval of the Merger.

On May 16, 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a settlement (Settlement) in which the parties agree that the Merger is in the public interest and recommend approval by the ACC, subject to certain conditions. Those conditions include, but are not limited to, the following:

• UNS Energy shall provide credits on the Regulated Utilities retail customers' bills totaling $30 million over five years; $10 million in year one and $5 million annually in years two through five. The monthly bill credits will be applied each year from October through March. If the Merger closes by the end of September 2014, the bill credits will commence on October 1, 2014;

• UNS Energy and the Regulated Utilities will adopt certain ring-fencing and corporate governance provisions;

• Dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014; and

• Fortis shall make an equity investment totaling $220 million through UNS Energy into the Regulated Utilities following closing of the Merger. However, if the Merger closes after September 30, 2014, the equity investment may be made into UNS Energy to retire debt.

The Settlement also requests that the ACC issue an order approving the Settlement no later than September 18, 2014. Hearings before an ACC administrative law judge on the Settlement concluded on June 17, 2014. The Settlement is subject to the review and approval of the ACC, which could approve, reject, or require modifications to the Settlement as a condition of approval of the Merger.

The completion of the Merger is also subject to the absence of any injunction, order, or other law prohibiting the Merger.

If the Merger is approved by the ACC in September 2014 as requested by the parties to the Settlement, we expect the Merger to close by the end of September 2014. Upon completion of the Merger, UNS Energy expects to record approximately $19 million of merger-related expenses including investment banker fees, legal fees, and accelerated expenses for certain share-based compensation awards. TEP would record approximately $15 million as its allocated share of these merger-related expenses. See Note 2 and Note 9.

Operating Plans and Strategies

Our financial prospects and outlook are affected by many factors including: national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:

• Completing the proposed merger with Fortis including obtaining all necessary approvals.

• Completing the purchases of Gila River Unit 3 and certain interests in Springerville Unit 1, which are both key components of our long-term diversification strategy for our generation portfolio. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.

37

• Strengthening the underlying financial condition of our utility subsidiaries by achieving constructive regulatory outcomes, improving our capital structure and our credit ratings, and promoting economic development in our service territories.

• Developing strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas emissions. We are evaluating TEP's existing mix of generation resources and defining steps to achieve environmental objectives that protect the financial stability of our utility businesses.

• Focusing on our core utility businesses through operational excellence, investing in utility rate base, emphasizing customer service, and maintaining a strong community presence.

• Developing strategic responses to Arizona’s requirements for renewable energy, distributed generation, and energy efficiency that protect the financial stability of our business while providing benefits for our customers.

RESULTS OF OPERATIONS

Contribution by Business Segment

The table below shows the contributions to our consolidated net income by business segment:

	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
	Millions of Dollars
TEP	$	39		$	31	$	48		$	32
UNS Electric	4			4		6			6
UNS Gas	—			—		5			8
Other Non-Reportable Segments and Adjustments (1)	(1		)	—		(1		)	—
Consolidated Net Income	$	42		$	35	$	58		$	46

⁽¹⁾  Includes: UNS Energy parent company expenses; Millennium; UED; and inter-company eliminations.

Executive Overview

Second quarter of 2014 compared with the second quarter of 2013

TEP

TEP reported net income of $39 million in the second quarter of 2014 compared with net income of $31 million in the same period last year. TEP's net income in the second quarter of 2013 included an income tax benefit of $11 million and a $3 million pre-tax charge recorded to fuel expense related to a credit to customers, both resulting from the 2013 TEP Rate Order.

TEP's pre-tax retail margin revenues increased by $22 million due to a Base Rate increase effective July 1, 2013, including $1 million of LFCR revenues related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 (See Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order and Note 3).

See Tucson Electric Power, Results of Operations.

UNS Electric

UNS Electric reported net income of $4 million in the second quarters of both 2014 and 2013. See UNS Electric, Results of Operations.

UNS Gas

UNS Gas reported no net income or loss in the second quarters of both 2014 and 2013. See UNS Gas, Results of Operations.

38

Six months endedJune 30, 2014 compared with the six months endedJune 30, 2013

TEP

TEP reported net income of $48 million in the first six months of 2014 compared with net income of $32 million in the same period last year. TEP's net income in the first six months of 2013 included an income tax benefit of $11 million and $3 million recorded to fuel expense related to a credit to customers, both resulting from the 2013 TEP Rate Order.

TEP's pre-tax retail margin revenues increased by $34 million due to a Base Rate increase effective July 1, 2013, including $6 million of LFCR revenues related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014 (See Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order and Note 3).

See Tucson Electric Power, Results of Operations.

UNS Electric

UNS Electric reported net income of $6 million in both the first six months of 2014 and 2013. See UNS Electric, Results of Operations.

UNS Gas

UNS Gas reported net income of $5 million in the first six months of 2014 compared with net income of $8 million in the same period last year. The decrease in net income is due primarily to lower sales volumes resulting from mild winter weather, which contributed to a decline in retail margin revenues. See UNS Gas, Results of Operations.

Operations and Maintenance Expense

The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense. Base O&M in the first six months of 2014 includes merger-related expenses of $1 million.

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars
UNS Energy Base O&M (Non-GAAP)(1)	$	68	$	71	$	141	$	141
Reimbursed Expenses Related to Springerville Units 3 and 4	17		16		31		30
Expenses Related to Customer-Funded Renewable Energy and DSM Programs(2)	7		8		13		14
Total UNS Energy O&M (GAAP)	$	92	$	95	$	185	$	185

⁽¹⁾  Base O&M, a non-GAAP financial measure, should not be considered as an alternative to O&M, which is determined in accordance with GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.

⁽²⁾  Represents expenses related to customer-funded renewable energy and DSM programs; these expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

39

LIQUIDITY AND CAPITAL RESOURCES

UNS Energy Consolidated Liquidity

Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, UNS Energy will use, as needed, its revolving credit facility to assist in funding its business activities. The table below provides a summary of the liquidity position of UNS Energy and each of its segments:

Balances at June 30, 2014	Cash and  Cash Equivalents		Borrowings and LOCs issued under Revolving Credit Facility		Amount Available under Revolving Credit Facility
	Millions of Dollars
UNS Energy Stand-Alone	$	2	$	75	$	50
TEP	43		16		184
UNS Electric(1)	4		23		47
UNS Gas(1)	18		—		70
Other(2)	3		N/A		N/A
Total	$	70

⁽¹⁾  Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both companies cannot exceed $100 million.

⁽²⁾  Includes cash and cash equivalents at Millennium and UED.

In the second quarter of 2014, TEP provided a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Tucson Electric Power, Factors Affecting Results of Operations, Gila River Generating Station Unit 3.

In July 2014, TEP made additional borrowings under its revolving credit facility to help fund scheduled capital lease payments. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.

Dividends from UNS Energy’s subsidiaries represent the parent company’s main source of liquidity.

Dividends from Subsidiaries

UNS Energy received $10 million of dividends from UNS Gas in the first six months of 2014 and 2013.

Short-term Investments

UNS Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update this policy in response to market conditions. At June 30, 2014, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit.

Access to Revolving Credit Facilities

We have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP Revolving Credit Facility and UNS Electric/UNS Gas Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Electric, and UNS Gas each issue LOCs from time to time to provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs for general corporate purposes.

We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. See Item 3 Quantitative and Qualitative Disclosures about Market Risk.

40

UNS Energy Consolidated Cash Flows

	Six Months Ended June 30,
	2014			2013
	Millions of Dollars
Operating Activities	$	138		$	148
Investing Activities	(190		)	(150		)
Financing Activities	47			(52		)
Net Increase (Decrease) in Cash	(5		)	(54		)
Beginning Cash	75			124
Ending Cash	$	70		$	70

UNS Energy’s operating cash flows are generated primarily by retail and wholesale energy sales at the Regulated Utilities, net of the related payments for fuel and purchased power. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer-peaking load. The Regulated Utilities typically use their revolving credit facilities to assist in funding their business activities during periods when sales are seasonally lower.

Capital expenditures at TEP, UNS Electric, and UNS Gas represent the primary use of cash for investing activities.

Cash used for investing and financing activities can fluctuate year-to-year depending on: capital expenditures; repayments and borrowings under revolving credit facilities; debt issuances or retirements; capital lease payments by TEP; and dividends paid by UNS Energy to its shareholders.

Operating Activities

In the first six months of 2014, net cash flows from operating activities were $10 million lower than they were in the same period last year. The following items affected the year-over-year change in operating cash flows: a $13 million decrease in operating cash flows at UNS Gas due to lower retail therm sales and the return of the over-collected PGA balance to customers; and a $22 million increase in payments of operations and maintenance costs and wages paid due to generation maintenance, customer incentives related to renewable programs, and Merger costs; partially offset by a $7 million increase in cash receipts from retail and wholesale sales, net of fuel and purchased power, at TEP and UNS Electric due primarily to Base Rate increases; a $6 million increase in cash receipts due to insurance proceeds related to the San Juan mine fire; a $3 million decrease in interest paid, net of amounts capitalized, due to the replacement of higher cost debt with lower cost debt in 2013; a $3 million decrease in interest paid on capital lease obligations due to a decline in the balance of capital lease obligations; and a $4 million decrease in taxes paid, net of amounts capitalized, due to a decrease in sales tax rates effective in June 2013.

Investing Activities

Net cash flows used for investing activities increased $40 million in the first six months of 2014 compared with the same period last year due in part to a $30 million increase in capital expenditures and a $9 million decrease in the return of investment in Springerville lease debt. The increase in capital expenditures is due in part to maintenance on our generating facilities and the construction of new solar projects.

Financing Activities

Net cash flows from financing activities were $99 million higher in the first six months of 2014 when compared with the same period last year due to: the issuance of $150 million of long-term debt by TEP in March 2014; partially offset by a $44 million decrease in borrowings (net of repayments) under the revolving credit facilities; and a $4 million increase in dividends paid on Common Stock.

UNS Credit Agreement

The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. At June 30, 2014, there was $75 million outstanding at a weighted-average interest rate of 1.40%. The UNS Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UNS Credit Agreement also requires UNS Energy to meet a minimum cash flow to debt service coverage ratio determined on a UNS Energy stand-alone basis. Additionally, UNS Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UNS Credit Agreement, UNS Energy may pay dividends so long as it maintains compliance with the agreement. UNS Energy’s obligations under the agreement are secured by a pledge of the common stock of Millennium, UES, and UED.

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If the Merger is approved by the ACC, dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with U.S. Generally Accepted Accounting Principles.

The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014.

At June 30, 2014, we were in compliance with the terms of the UNS Credit Agreement.

Interest Rate Risk

UNS Energy is subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. UNS Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if LIBOR and other benchmark interest rates increase. See Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Contractual Obligations

There are no changes in our contractual obligations or other commercial commitments from those reported in our 2013 Annual Report on Form 10-K, other than the following changes in 2014:

• In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. See Note 5.

• In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is then obligated to either 1) buy a portion of the facilities for $24 million or 2) continue to make payments to TEP for the use of the facilities. See Note 5.

• We entered into new forward purchased power commitments with minimum payment obligations of $23 million in 2015. See Note 6.

• We entered into new forward energy commitments with minimum payment obligations of $9 million in 2015 through 2017 and $8 million in each of 2018 and 2019. See Note 6.

Dividends on Common Stock

In first six months of 2014, UNS Energy paid dividends on Common Stock of $40 million. The following table shows the dividends declared to UNS Energy shareholders for 2014:

Declaration Date	Record Date	Payment Date	Dividend Amount Per Share  of Common Stock
February 24, 2014	March 13, 2014	March 25, 2014	$	0.48
May 1, 2014	June 6, 2014	June 26, 2014	$	0.48

The Merger permits UNS Energy to pay quarterly dividends of up to $0.48 per share of common stock during 2014. The Merger also permits a stub period dividend to shareholders of record at the close of the Merger equal to the product of (i) the number of days from the record date of the most recent dividend payment and the effective time of the close of the Merger and (ii) the daily dividend rate. The daily dividend rate is determined by dividing the amount of the last quarterly dividend by 91. If the Merger is completed, UNS Energy's board of directors may declare a stub period dividend.

Income Tax Position

The 2010 Federal Tax Relief Act and the American Taxpayer Relief Act of 2012 include provisions that make qualified property placed in service between 2010 and 2013 eligible for bonus depreciation for tax purposes. In addition, the IRS issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits UNS Energy and TEP otherwise would have received over 20 years and have created net operating loss carryforwards that can be used to offset future taxable income.  As a result, UNS Energy and TEP do not expect to pay any federal or state income taxes through 2017.  However, if the Merger is approved, UNS Energy and TEP will be limited in the

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amount of net operating loss carryforward that can be used annually, which is expected to result in Federal tax payments in 2015.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

TEP’s financial condition and results of operations are the principal factors affecting the financial condition and results of operations of UNS Energy. The following discussion relates to TEP, unless otherwise noted.

Second quarterof2014 compared with the second quarterof2013

TEP reported net income of $39 million in the second quarter of 2014 compared with net income of $31 million in the second quarter of 2013. The following factors affected the change in TEP’s pre-tax results in the second quarter of 2014:

• a $22 million increase in Retail Margin Revenues due to a Base Rate increase that was effective on July 1, 2013. See Factors Affecting Results of Operations, 2013 TEP Rate Order, below, and Note 3;

• a $1 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;

• a $2 million decrease in Base O&M due in part to certain costs now being recovered through fuel and purchased power expense as a result of the 2013 TEP Rate Order; and

• a $1 million decrease in interest expense due to a reduction in the balance of capital lease obligations; partially offset by

• a $1 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

TEP's results in the second quarter of 2013 include: an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates (See Note 13); and a pre-tax charge of $3 million recorded in June 2013 to fuel and purchased energy expense. Both items were a result of the 2013 TEP Rate Order.

Six months endedJune 30, 2014 compared with the six months endedJune 30, 2013

TEP reported net income of $48 million in the first six months of 2014 compared with net income of $32 million in the first six months of 2013. The following factors affected TEP’s pre-tax results in the first six months of 2014:

• a $34 million increase in Retail Margin Revenues due to a Base Rate increase that was effective on July 1, 2013, which includes $6 million of LFCR revenues recorded in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2014 and 2013. See Factors Affecting Results of Operations, 2013 TEP Rate Order, below, and Note 3;

• a $2 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power; and

• a $4 million decrease in interest expense due to a reduction in the balance of capital lease obligations; partially offset by

• a $2 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

TEP's results in the first six months of 2013 include: an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates (See Note 13); and a pre-tax charge of $3 million recorded in June 2013 to fuel and purchased energy expense. Both items were a result of the 2013 TEP Rate Order.

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Utility Sales and Revenues

The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the second quarters of 2014 and 2013:

	Three Months Ended June 30,				Increase (Decrease)
	2014		2013		Amount			Percent(1)
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	986		1,002		(16		)	(1.6	)%
Commercial(2)	585		599		(14		)	(2.3	)%
Industrial	526		543		(17		)	(3.1	)%
Mining	284		258		26			10.1	%
Other(2)	8		8		—			—	%
Total Electric Retail Sales	2,389		2,410		(21		)	(0.9	)%
Retail Margin Revenues (in Millions):
Residential	$	74	$	65	$	9		13.8	%
Commercial(2)	53		47		6			12.8	%
Industrial	28		24		4			16.7	%
Mining	10		8		2			25.0	%
Other(2)	1		1		—			—	%
Total by Customer Class	166		145		21			14.5	%
LFCR Revenues	1		—		1			NM
Total Retail Margin Revenues (Non-GAAP)(3)	167		145		22			15.2	%
Fuel and Purchased Power Revenues	79		87		(8		)	(9.2	)%
RES, DSM, and ECA Revenues	12		12		—			—	%
Total Retail Revenues (GAAP)	$	258	$	244	$	14		5.7	%
Average Retail Margin Rate (Cents / kWh):(1)
Residential	7.51		6.54		0.97			14.8	%
Commercial(2)	9.06		7.85		1.21			15.4	%
Industrial	5.32		4.44		0.88			19.8	%
Mining	3.52		3.09		0.43			13.9	%
Other(2)	12.50		12.50		—			—	%
Total Average by Customer Class	6.95		6.02		0.93			15.4	%
Average LFCR Revenues	0.04		—		0.04			NM
Average Retail Margin Revenues	6.99		6.03		0.96			15.9	%
Average Fuel and Purchased Power Revenues	3.31		3.59		(0.28		)	(7.8	)%
Average RES, DSM, and ECA Revenues	0.50		0.49		0.01			2.0	%
Total Average Retail Revenues	10.80		10.11		0.69			6.8	%
Weather Data:
Cooling Degree Days
Three Months Ended June 30,	550		577		(27		)	(4.7	)%
10-Year Average	478		463		NM			NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

⁽²⁾  Retail kWh sales to commercial and other customers and associated retail margin revenues for 2013 have been adjusted to reflect a change in the methodology for counting customers resulting from rate design changes from the 2013 TEP Rate Order.

⁽³⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales and LFCR revenues available to cover the non-fuel operating expenses of our core utility business.

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Retail kWh Sales and Margin Revenues

TEP's total retail kWh sales decreased by 0.9% in the second quarter of 2014 due in part to (i) a 4.7% decrease in cooling degree days compared with the second quarter of 2013 and (ii) ongoing energy efficiency programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $22 million, or 15.2%, due to a Base Rate increase that was effective on July 1, 2013 and $1 million of LFCR revenues recorded in the second quarter of 2014.

Mining kWh sales increased by 10.1% compared with the second quarter of 2013 due in part to an expansion of one of our customer's mines in October 2013.

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The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the first six months of 2014 and 2013:

	Six Months Ended June 30,				Increase (Decrease)
	2014		2013		Amount			Percent(1)
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	1,654		1,795		(141		)	(7.9	)%
Commercial(2)	1,029		1,050		(21		)	(2.0	)%
Industrial	997		1,016		(19		)	(1.9	)%
Mining	563		528		35			6.6	%
Other(2)	17		16		1			6.3	%
Total Electric Retail Sales	4,260		4,405		(145		)	(3.3	)%
Retail Margin Revenues (in Millions):
Residential	$	125	$	116	$	9		7.8	%
Commercial(2)	87		80		7			8.8	%
Industrial	51		44		7			15.9	%
Mining	19		14		5			35.7	%
Other(2)	1		1		—			—	%
Total by Customer Class	283		255		28			11.0	%
LFCR Revenues	6		—		6			NM
Total Retail Margin Revenues (Non-GAAP)(2)	289		255		34			13.3	%
Fuel and Purchased Power Revenues	131		151		(20		)	(13.2	)%
RES, DSM and ECA Revenues	24		23		1			4.3	%
Total Retail Revenues (GAAP)	$	444	$	429	$	15		3.5	%
Average Retail Margin Rate (Cents / kWh):(1)
Residential	7.56		6.44		1.12			17.4	%
Commercial(2)	8.45		7.62		0.83			10.9	%
Industrial	5.12		4.28		0.84			19.6	%
Mining	3.37		2.75		0.62			22.5	%
Other(2)	5.88		6.25		(0.37		)	(5.9	)%
Total Average by Customer Class	6.64		5.79		0.85			14.7	%
Average LFCR Revenues	0.14		—		0.14			NM
Average Retail Margin Revenues	6.78		5.79		0.99			17.1	%
Average Fuel and Purchased Power Revenues	3.08		3.42		(0.34		)	(9.9	)%
Average RES, DSM and ECA Revenues	0.56		0.51		0.05			9.8	%
Total Average Retail Revenue	10.42		9.72		0.70			7.2	%
Weather Data:
Cooling Degree Days
Six Months Ended June 30,	550		577		(27		)	(4.7	)%
10-Year Average	478		463		NM			NM
Heating Degree Days
Six Months Ended June 30,	455		983		(528		)	(53.7	)%
10-Year Average	819		867		NM			NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

⁽²⁾  Retail kWh sales to commercial and other customers and associated retail margin revenues for 2013 have been adjusted to reflect a change in the methodology for counting customers resulting from rate design changes from the 2013 TEP Rate Order.

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⁽³⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales and LFCR revenues available to cover the non-fuel operating expenses of our core utility business.

Retail kWh Sales and Margin Revenues

TEP's total retail kWh sales decreased by 3.3% in the first six months of 2014 due in part to: a 4.7% decrease in cooling degree days compared with the first six months of 2013; a 55.0% decrease in heating degree days during the first three months of 2014 compared with the first three months of 2013; and ongoing energy efficiency programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $34 million, or 13.3%, due to a Base Rate increase that was effective on July 1, 2013 and $6 million of LFCR revenues recorded in the first six months of 2014.

Mining kWh sales increased by 6.6% compared with the first six months of 2013 due in part to an expansion of one of our customer's mines in October 2013.

Wholesale Sales and Transmission Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)	$	2	$	1	$	6	$	4
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues	5		4		9		9
Total Long-Term Wholesale Revenues	7		5		15		13
Transmission Revenues	4		4		8		8
Short-Term Wholesale Revenues	22		21		52		43
Electric Wholesale Sales (GAAP)	$	33	$	30	$	75	$	64

⁽¹⁾  Long-term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change in Long-Term Wholesale Margin Revenues between periods provides useful information to investors because it demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business.

Long-Term Wholesale Margin Revenues in the first six months of 2014 were higher when compared with the first six months of 2013 due in part to higher market prices for wholesale power.

All revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.

Other Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars				Millions of Dollars
Revenue related to Springerville Units 3 and 4(1)	$	24	$	24	$	46	$	45
Other Revenue	7		7		13		15
Total Other Revenue	$	31	$	31	$	59	$	60

⁽¹⁾ Represents revenues and reimbursements from Tri-State and SRP, owners of Springerville Units 3 and 4, respectively, to TEP related to the operation of these plants.

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In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include inter-company revenues from UNS Gas and UNS Electric for corporate services provided by TEP, and miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees.

Operating Expenses

Generating Output and Fuel and Purchased Power Expense

Total generating output decreased in the second quarter and first six months of 2014 when compared with the same periods last year due in part to maintenance outages .

TEP’s fuel and purchased power expense and energy resources for the quarters ended June 30, 2014 and 2013 are detailed below:

	Generation and Purchased Power				Fuel and Purchased Power Expense
	Three Months Ended June 30,
	2014		2013		2014			2013
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	1,907		2,639		$	50		$	71
Gas-Fired Generation	306		232		16			12
Utility Owned Renewable Generation	12		13		—			—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		2			2
Total Fuel	2,225		2,884		68			85
Total Purchased Power	1,107		544		53			28
Transmission and Other PPFAC Recoverable Costs	—		—		4			2
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		(13		)	5
Total Resources	3,332		3,428		$	112		$	120
Less Line Losses and Company Use	(230	)	(248	)
Total Energy Sold	3,102		3,180

TEP’s fuel and purchased power expense and energy resources for the first six months of 2014 and 2013 are detailed below:

	Generation and Purchased Power				Fuel and Purchased Power Expense
	Six Months Ended June 30,
	2014		2013		2014			2013
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	4,202		5,110		$	106		$	142
Gas-Fired Generation	546		418		27			20
Utility Owned Renewable Generation	22		24		—			—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		3			3
Total Fuel	4,770		5,552		136			165
Total Purchased Power	1,547		973		76			47
Transmission and Other PPFAC Recoverable Costs	—		—		7			3
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		(15		)	3
Total Resources	6,317		6,525		$	204		$	218
Less Line Losses and Company Use	(397	)	(420	)
Total Energy Sold	5,920		6,105

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The table below summarizes TEP’s average fuel cost per kWh generated or purchased:

	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
	cents per kWh
Coal	2.64	2.71	2.52	2.78
Gas	5.34	4.99	5.02	4.71
Purchased Power	4.78	5.22	4.88	4.87
All Sources	4.02	3.61	3.70	3.53

O&M

The table below summarizes the items included in TEP’s O&M expense. Base O&M in the first six months of 2014 includes merger-related expenses of $1 million.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Base O&M (Non-GAAP)(1)	$	59		$	61		$	122		$	122
O&M Recorded in Other Expense	(2		)	(1		)	(4		)	(3		)
Reimbursed Expenses Related to Springerville Units 3 and 4	17			16			31			30
Expenses Related to Customer Funded Renewable Energy and DSM Programs(2)	6			6			12			11
Total O&M (GAAP)	$	80		$	82		$	161		$	160

⁽¹⁾  Base O&M is a non-GAAP financial measure and should not be considered as an alternative to O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is O&M less reimbursed expenses and expenses related to customer-funded renewable energy and DSM programs, provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business.

⁽²⁾  Represents expenses related to customer-funded renewable energy and DSM programs; these expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

The table below summarizes TEP’s pension and other retiree benefit expenses included in TEP's Base O&M:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars
Pension Expense Charged to O&M	$	1	$	3	$	3	$	5
Retiree Benefit Expense Charged to O&M	1		1		2		2
Total	$	2	$	4	$	5	$	7

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 TEP Rate Order

The provisions of the 2013 TEP Rate Order, which were effective July 1, 2013, include, but are not limited to:

• An increase in Base Rates of approximately $76 million.

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

• An LFCR mechanism that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to energy efficiency programs and distributed generation. The LFCR rate will be adjusted annually and is subject to ACC review and a year-over-year cap of 1% of TEP's total retail revenues. TEP

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filed its first LFCR report with the ACC in May 2014. The report requested recovery of approximately $5 million. We expect the new LFCR rate to be effective August 1, 2014. TEP recorded LFCR revenues of $6 million in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. See Note 3.  TEP estimates that it will record total LFCR revenues of approximately $11 million during 2014.

• An ECA mechanism that allows TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA will be adjusted annually to recover environmental compliance costs and is subject to ACC approval and a cap of $0.00025 per kWh, which approximates 0.25% of TEP's total retail revenues. TEP filed its first ECA report in March 2014 to recover the return on and of qualified investments of approximately $3 million. The ECA rate became effective on May 1, 2014. TEP estimates that it will record total ECA revenues of less than $1 million in 2014.

As required by the 2013 Rate Order, TEP filed a compliance report in July 2014 that outlines its planned purchases of: (i) certain ownership interests in Springerville Unit 1; (ii) 75% of Gila River Unit 3; and (iii) the Springerville Coal Handling Facilities. The report estimates that as a result of these purchases, and the termination of certain lease obligations, TEP's 2014 non-fuel revenue requirement would decline by approximately $36 million. However, when other changes to TEP's rate base, expenses and retail sales levels are considered, we estimate that TEP would have a non-fuel revenue deficiency of approximately $26 million as of December 31, 2014.

See Coal-Fired Generating Resources and Springerville Coal Handling Facilities Leases, below, for more information.

Generating Resources

At June 30, 2014, approximately 70% of TEP's generating capacity was fueled by coal (of which 120 MW can be converted to 156 MW of natural gas capacity at Sundt Unit 4). Existing and proposed federal environmental regulations, as well potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is evaluating various strategies for reducing the proportion of coal in its fuel mix. TEP's ability to reduce its coal-fired generating capacity will depend on several factors, including, but not limited to:

• the resolution of the non-binding agreement between the State of New Mexico, the EPA, and PNM as it relates to San Juan, see Part II, Item. 5 - Other Information, Environmental Matters;

• TEP's option to permanently convert Sundt Unit 4 to be fueled by natural gas, see Part II, Item. 5 - Other Information, Environmental Matters;

• TEP's future ownership interest in Springerville Unit 1, see Springerville Unit 1, below; and

• the planned purchase of Gila River Unit 3, a combined cycle natural gas plant, see Gila River Generating Station Unit 3, below.

Springerville Unit 1

TEP leases Unit 1 of the Springerville Generating Station and an undivided one-half interest in certain Springerville Common Facilities (collectively Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that are accounted for as capital leases. The leases expire in January 2015 and include fair market value renewal and purchase options. In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 MW of capacity.

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.

During 2013, TEP agreed to purchase undivided ownership interests in Springerville Unit 1 totaling 35.4%, or 137 MW. The purchase price is the same as the appraisal value of $478 per kW, or approximately $65 million.

Upon the close of these lease option purchases in December 2014 and January 2015, 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 to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets in the aggregate amount of approximately $55 million.

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TEP does not expect that its final undivided ownership interest in Springerville Unit 1 will exceed 49.5%, or 192 MW of capacity. The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, will be owned by third parties. TEP is not obligated to purchase any of the remaining power from Springerville Unit 1; however, TEP is obligated to operate Springerville Unit 1 for the remaining third-party owners after January 2015, the expiration date of the leases. TEP is currently discussing its post-January 2015 operation of Springerville Unit 1, including capital and O&M cost allocations, with the remaining third-party owners.

TEP expects to replace the 195 MW of expiring leased capacity with the purchase of Gila River Unit 3. See Gila River Generating Station Unit 3, below.

Gila River Generating Station Unit 3

In December 2013, TEP and UNS Electric entered into an agreement (the Purchase Agreement) to purchase Gila River Unit 3 for $219 million from a subsidiary of Entegra. The purchase price is subject to adjustments to prorate certain fees and expenses through the closing and in respect of certain operational matters. It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014.

On June 13, 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Purchase Agreement under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

The Purchase Agreement remains subject to, among other things:

• the approval of the FERC;

• the completion of certain other agreements associated with the operation of Gila River Unit 3; and

• other customary closing conditions.

In June 2014, TEP provided a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the Purchase Agreement. The seller of Gila River Unit 3 is entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the Purchase Agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled.

The purchase of Gila River Unit 3, which would replace the expiring coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, is consistent with TEP's strategy to diversify its generation fuel mix. See Note 6.

In December 2013, UNS Electric filed an application requesting the ACC to approve an accounting order that would authorize UNS Electric to defer for future recovery specific non-fuel operating costs associated with its anticipated ownership of 25% of Gila River Unit 3. See UNS Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 7.

Springerville Coal Handling Facilities Leases

TEP leases interests in the coal handling facilities at the Springerville Generating Station (Springerville Coal Handling Facilities) under two separate lease agreements (Springerville Coal Handling Facilities Leases). The lease agreements have an initial term that expires in April 2015 and provide TEP the option to renew the leases or to purchase the leased interests at the aggregate fixed price of $120 million.

In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, TEP recorded, in the second quarter of 2014, an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheets in the amount of $109 million, which represented the present value of the total purchase commitment.

TEP previously agreed with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP’s purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for

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approximately $24 million and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities.

Sales to Mining Customers

TEP's mining customers have indicated they are taking initial steps to increase production either through expansion of their current mining operations or by the re-opening of non-operational mine sites. If efforts to increase production are successful, TEP's mining load could increase by up to 90 MW over the next several years. The market price for copper and the ability to obtain necessary permits could affect the mining industry's expansion plans.

In addition to the mining customers that TEP currently serves, Augusta Resources Corporation filed a plan of operations with the United States Forest Service in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona.  The construction and ongoing operations of Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line. In 2012, the ACC approved a Certificate of Environmental Compatibility (CEC) authorizing TEP to build the line to serve the mine. If the Rosemont Copper Mine is constructed and reaches full production, it would be expected to become TEP's largest retail customer, with TEP serving the mine's estimated load of approximately 85 MW.

TEP cannot predict if or when existing mines will expand operations or new or re-opened mines will commence operations.

Springerville Units 3 and 4

TEP receives annual benefits in the form of rental payments and other fees and cost savings from operating Springerville Unit 3 on behalf of Tri-State and Unit 4 on behalf of SRP.

The table below summarizes the income statement line items in which TEP records revenues and expenses related to Springerville Units 3 and 4:

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Other Revenues	$	24		$	24		$	46		$	45
Fuel Expense	(2		)	(2		)	(3		)	(3		)
O&M Expense	(17		)	(16		)	(31		)	(30		)
Taxes Other Than Income Taxes	—			—			(1		)	(1		)

Interest Rates

See Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Fair Value Measurements

See Note 12.

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LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

The tables below show TEP's net cash flows after capital expenditures, scheduled lease debt payments, and payments on capital lease obligations:

	Six Months Ended June 30,
	2014			2013
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	113		$	116
Less: Capital Expenditures	(157		)	(118		)
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)	(44		)	(2		)
Less: Payments of Capital Lease Obligations	(83		)	(84		)
Plus: Proceeds from Investment in Lease Debt	—			9
Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations (Non-GAAP)(1)	$	(127	)	$	(77	)

	Six Months Ended June 30,
	2014			2013
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	113		$	116
Net Cash Flows – Investing Activities (GAAP)	(160		)	(113		)
Net Cash Flows – Financing Activities (GAAP)	65			(55		)
Net Increase (Decrease) in Cash	18			(52		)
Beginning Cash	25			80
Ending Cash	$	43		$	28

⁽¹⁾  Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows—Operating Activities, which is determined in accordance with GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make required payments on lease debt and capital lease obligations, and pay dividends to UNS Energy before consideration of financing activities.

Liquidity Outlook

Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to assist in funding its business activities.

If the Merger with Fortis is approved by all necessary parties, the terms of the Settlement provide that Fortis will make an equity investment of $220 million in UNS Energy within 60 days after closing. If the Merger closes by September 30, 2014, the equity contribution from Fortis will be contributed to the Regulated Utilities, including TEP, to help fund the Gila River Unit 3 and Springerville Unit 1 purchase commitments.

Operating Activities

In the first six months of 2014, net cash flows from operating activities were $3 million lower than in the same period last year. The decrease was due primarily to: a $21 million increase in operations and maintenance costs and wages paid due to planned and unplanned maintenance outages, customer incentives related to renewable programs, and merger-related costs; partially offset by a $6 million increase in cash receipts due to insurance proceeds related to the San Juan mine fire; $6 million of lower interest paid on debt and capital leases; a $3 million increase in cash receipts from retail and electric sales, net of fuel and purchased power costs paid due to a Base Rate increase at TEP that was effective on July 1, 2013; and a $2 million decrease in taxes paid, net of amounts capitalized.

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Investing Activities

Net cash flows used for investing activities increased by $48 million in the first six months of 2014 compared with the same period last year due primarily to an $39 million increase in capital expenditures due in part to maintenance on our generating facilities and the construction of new solar projects. Cash flows from investing activities in the first six months of 2014 also included a $9 million reduction in return of investments in lease debt.

Financing Activities

In the first six months of 2014, net cash from financing activities was $120 million higher than the same period last year due to proceeds from the issuance of $150 million of long-term debt offset by $30 million more in repayments (net of borrowings) under the TEP Revolving Credit Facility.

2014 Bond Issuances

In March 2014, TEP issued $150 million of unsecured notes. The bonds bear interest at a fixed rate of 5.0%, mature in March 2044, and may be redeemed at par on or after September 15, 2043. The proceeds of the bond issuance were used to repay approximately $90 million outstanding under TEP's revolving credit facility, with the remaining proceeds to be applied to general corporate purposes. See Note 5.

TEP Credit Agreement

The TEP Credit Agreement consists of a $200 million revolving credit and LOC facility, and a separate $82 million LOC facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016. See Note 5.

TEP provided, in the second quarter of 2014, a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 7.

At June 30, 2014, there were no outstanding borrowings and there were $16 million of LOCs issued under the revolving credit and LOC facility, leaving $184 million of available borrowing capacity.

In July 2014, TEP made additional borrowings under its revolving credit facility to help fund scheduled capital lease payments. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.

The TEP Credit Agreement contains restrictions on mergers and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UNS Energy. At June 30, 2014, TEP was in compliance with the terms of the TEP Credit Agreement. See Note 5.

2010 TEP Reimbursement Agreement

In December 2010, TEP entered into a four-year $37 million reimbursement agreement (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 pollution control bonds that were issued on behalf of TEP in December 2010.

In February 2014, TEP amended the 2010 TEP Reimbursement Agreement to extend the expiration date of the LOC from 2014 to 2019.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. At June 30, 2014, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

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Capital Lease Obligations

At June 30, 2014, TEP had $343 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease obligations:

	Capital Lease  Obligation Balance As Of
Capital Leases	June 30, 2014		Expiration	Renewal/Purchase Option
	Millions of Dollars
Springerville Unit 1(1)	$	129	2015	Fair market value
Springerville Coal Handling Facilities	131		2015	Fixed price purchase option of $120 million(2)
Springerville Common Facilities(3)	83		2017 and 2021	Fixed price purchase option of $106 million(3)
Total Capital Lease Obligations	$	343

⁽¹⁾  The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. The $129 million balance includes the present value of the lease purchase options agreed to in 2013.

⁽²⁾  The $131 million balance includes the present value of the lease purchase options elected in April 2014. Upon TEP’s purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. See Factors Affecting Results of Operations, Springerville Coal Handling Facilities Leases. Also see Note 5.

⁽³⁾  The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities.

TEP's capital lease obligation balances decline over time due to the normal capital lease payments made by TEP.

Income Tax Position

See UNS Energy Consolidated, Liquidity and Capital Resources, Income Tax Position.

Contractual Obligations

There have been no changes in TEP's contractual obligations or other commercial commitments from those reported in our 2013 Annual Report on Form 10-K, other than the following changes in 2014:

• In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. See Note 5.

• In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase its undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for $24 million or 2) continue to make payments to TEP for the use of the facilities. See Note 5.

• TEP entered into new forward purchased power commitments with minimum payment obligations of $15 million million in 2015. See Note 6 .

• TEP entered into new forward energy commitments with minimum payment obligations of $8 million in 2015 through 2019. See Note 6.

We have reviewed our contractual obligations and provide the following additional information:

• The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement contain pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings, and the amount of fees it pays for its LOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facility.

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• The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement contain certain financial and other restrictive covenants, including a leverage test. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At June 30, 2014, TEP was in compliance with these covenants. See TEP Credit Agreement, above.

• TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of June 30, 2014, TEP had posted less than $1 million in LOCs as collateral with wholesale counterparties for credit enhancement.

• In June 2014, TEP provided a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. See Note 7.

Dividends on Common Stock

TEP did not pay any dividends to UNS Energy in the first six months of 2014 or 2013.

The pending Settlement related to the Merger contains a condition restricting subsidiary dividend payments to UNS Energy. See UNS Energy, Outlook and Strategies.

TEP can pay dividends to UNS Energy if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement. At June 30, 2014, TEP was in compliance with the terms of the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $4 million in the second quarters of 2014 and 2013. In the first six months of 2014 and 2013, UNSE Electric reported net income of $6 million.

Like TEP, UNS Electric’s operations are typically seasonal in nature, with peak energy demand occurring in the summer months. The table below provides summary financial information for UNS Electric:

	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014		2013
	Millions of Dollars
Retail Electric Revenues	$	45	$	42		$	84	$	78
Wholesale Electric Revenues	2		2			4		3
Total Operating Revenues	47		44			88		81
Purchased Energy Expense	20		20			39		37
Fuel Expense	1		2			1		3
Transmission Expense	3		3			7		6
Increase (Decrease) to Reflect PPFAC Recovery	1		(2		)	1		(4		)
O&M	7		7			14		15
Depreciation and Amortization Expense	5		5			10		9
Taxes Other Than Income Taxes	2		1			3		3
Total Operating Expenses	39		36			75		69
Operating Income	8		8			13		12
Interest Expense	2		2			4		3
Income Tax Expense	2		2			3		3
Net Income	$	4	$	4		$	6	$	6

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The tables below shows UNS Electric’s kWh sales and margin revenues:

	Three Months Ended June 30,				Increase (Decrease)
	2014		2013		Amount			Percent(1)
Electric Retail Sales, kWh (in Millions):
Residential	201		201		—			—	%
Commercial	165		170		(5		)	(2.9	)%
Industrial	48		49		(1		)	(2.0	)%
Mining	17		16		1			6.3	%
Total Electric Retail Sales	431		436		(5		)	(1.1	)%
Retail Margin Revenues (in Millions):
Residential	$	8	$	8	$	—		—	%
Commercial	8		8		—			—	%
Industrial	2		2		—			—	%
Mining	1		1		—			—	%
Total Retail Margin Revenues (Non-GAAP)(2)	19		19		—			—	%
Fuel and Purchased Power Revenues	24		21		3			14.3	%
RES & DSM Revenues	2		2		—			—	%
Total Retail Revenues (GAAP)	$	45	$	42	$	3		7.1	%
Weather Data:
Cooling Degree Days
Three Months Ended June 30,	1,162		1,221		(59		)	(4.8	)%
10-Year Average	1,037		1,029		NM			NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

⁽²⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales available to cover the non-fuel operating expenses of our core utility business.

Total retail kWh sales in the second quarter of 2014 decreased by 1.1% compared with the same period last year due in part to milder summer weather. Despite lower retail sales, total retail margin revenues in the second quarter of 2014 were the same when compared to the second quarter of 2013 due in part to a Base Rate increase effective January 1, 2014.

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	Six Months Ended June 30,				Increase (Decrease)
	2014		2013		Amount			Percent(1)
Electric Retail Sales, kWh (in Millions):
Residential	359		392		(33		)	(8.4	)%
Commercial	297		297		—			—	%
Industrial	92		91		1			1.1	%
Mining	31		29		2			6.9	%
Other	1		1		—			—	%
Total Electric Retail Sales	780		810		(30		)	(3.7	)%
Retail Margin Revenues (in Millions):
Residential	$	15	$	15	$	—		—	%
Commercial	14		14		—			—	%
Industrial	4		4		—			—	%
Mining	2		3		(1		)	(33.3	)%
Total by Customer Class	35		36		(1		)	(2.8	)%
LFCR Revenues	2		—		2			NM
Total Retail Margin Revenues (Non-GAAP)(2)	37		36		1			2.8	%
Fuel and Purchased Power Revenues	43		38		5			13.2	%
RES & DSM Revenues	4		4		—			—	%
Total Retail Revenues (GAAP)	$	84	$	78	$	6		7.7	%
Weather Data:
Cooling Degree Days
Six Months Ended June 30,	1,250		1,304		(54		)	(4.1	)%
10-Year Average	1,083		1,074		NM			NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

⁽²⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales and LFCR revenues available to cover the non-fuel operating expenses of our core utility business.

In the first six months of 2014, total retail kWh sales declined by 3.7% compared with the first six months of 2013 due in part to a 4.1% decrease in cooling degree days and due to milder weather in the first quarter of 2014 when compared with the first quarter of 2013. Total retail margin revenues increased by $1 million, or 2.8%. UNS Electric recorded LFCR revenues of $2 million in the first six months of 2014, a portion of which relates to reductions in 2013 retail kWh sales due to energy efficiency programs and distributed generation.

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 UNS Electric Rate Order

In December 2013, the ACC approved a new rate structure for UNS Electric that became effective on January 1, 2014 (2013 UNS Electric Rate Order). The provisions of the 2013 UNS Electric Rate Order include, but are not limited to:

• an increase in Base Rates of approximately $3 million;

• an LFCR mechanism that will allow UNS Electric to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to compliance with the ACC's Electric EE Standards and distributed generation requirements under the ACC's RES. The LFCR rate will be adjusted annually and is subject to

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ACC review and a year-over-year cap of 1% of UNS Electric's total retail revenues. The LFCR is not a full decoupling mechanism because it is not intended to recover lost fixed costs attributable to weather or economic conditions. UNS Electric filed its first LFCR report with the ACC in May 2014. The report requested recovery of approximately $1 million. We expect the new LFCR rate to be effective September 1, 2014. UNS Electric recorded LFCR revenues of $2 million in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. See Note 3. UNS Electric estimates that it will record total LFCR revenues of approximately $2 million during 2014; and

• a Transmission Cost Adjustor (TCA) mechanism that will allow more timely recovery of transmission costs associated with serving retail customers at the level approved by FERC. UNS Electric's approved Base Rates include a transmission component based on UNS Electric’s current FERC Open Access Transmission Tariff (OATT) rate. The OATT rates are adjusted annually and the TCA will be limited to the recovery (or refund) of costs associated with future changes in UNS Electric’s OATT rate. The TCA rate became effective in June 2014. UNS Electric estimates that it will record TCA revenues of $1 million in 2014.

Gila River Generating Station Unit 3

In December 2013, TEP and UNS Electric entered into an agreement to purchase Gila River Unit 3 for $219 million. It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014. See Tucson Electric Power, Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 7.

Also in December 2013, UNS Electric filed an application requesting the ACC to approve an accounting order that would authorize UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3. If UNS Electric purchases 25% of Gila River Unit 3, the deferred costs, including depreciation, amortization, property taxes, O&M expense and a carrying cost on UNS Electric's investment in Gila River Unit 3, are expected to total approximately $9 million annually. We cannot predict if the ACC will approve UNS Electric's request.

Fair Value Measurements

See Note 12.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric expects operating cash flows to fund a portion of its construction expenditures during 2014. Additional sources of funding capital expenditures could include draws on the UNS Electric/UNS Gas Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.

Cash Flows and Capital Expenditures

The table below provides summary cash flow information for UNS Electric:

	Six Months Ended June 30,
	2014			2013
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	20		$	12
Investing Activities	(22		)	(30		)
Financing Activities	1			14
Net Increase/(Decrease) in Cash	(1		)	(4		)
Beginning Cash	5			8
Ending Cash	$	4		$	4

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Operating Activities

Cash provided by operating activities increased by $8 million in the first six months of 2014 when compared with the same period last year due primarily to a $3 million increase in cash receipts from electric retail sales caused by a Base Rate increase that was effective on January 1, 2014 and a $4 million reduction in income taxes paid.

Investing Activities

UNS Electric had capital expenditures of $20 million in the first six months of 2014 compared with $29 million in the first six months of 2013. The decrease is related to the completion of a transmission line in 2013 to increase reliability to UNS Electric's service territory in Nogales, Arizona.

Financing Activities

Cash provided by financing activities at UNS Electric in the first six months of 2014 decreased by $13 million when compared with the same period last year. Financing activities in the first six months of 2014 included $1 million of borrowings under the UNS Electric/UNS Gas Revolver (net of repayments) whereas activity in the same period last year included $12 million of borrowings (net of repayments), and a $2 million receipt related to a contribution in aid of construction from a large customer.

UNS Electric/UNS Gas Credit Agreement

The UNS Electric/UNS Gas Credit Agreement consists of a $100 million unsecured revolving credit and revolving LOC facility. Either company can borrow up to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The UNS Electric/UNS Gas Credit Agreement expires November 2016.

UNS Electric is only liable for UNS Electric’s borrowings, and similarly, UNS Gas is only liable for UNS Gas' borrowings under the UNS Electric/UNS Gas Credit Agreement.

The UNS Electric/UNS Gas Credit Agreement restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. At June 30, 2014, UNS Electric and UNS Gas each were in compliance with the terms of the UNS Electric/UNS Gas Credit Agreement.

UNS Electric expects to draw upon the UNS Electric/UNS Gas Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At June 30, 2014, UNS Electric had $23 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Electric/UNS Gas Credit Agreement, leaving available borrowing capacity of $47 million.

Contractual Obligations

There are no changes in UNS Electric's contractual obligations or other commercial commitments from those reported in our 2013 Annual Report on Form 10-K, other than the following changes in 2014:

• UNS Electric entered into new forward purchased power commitments with minimum payment obligations of $8 million in 2015. See Note 6.

Dividends on Common Stock

UNS Electric did not pay any dividends to UNS Energy, through UES, in the first six months of 2014 and 2013. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The pending Settlement related to the Merger contains a condition restricting subsidiary dividend payments to UNS Energy. See UNS Energy, Outlook and Strategies.

The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as 1) no default or event of default exists, and 2) it could incur additional debt under the debt incurrence test. At June 30, 2014, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Electric/UNS Gas Revolver.

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UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported no net income or loss in the second quarters of 2014 and 2013. In the first six months of 2014, UNS Gas reported net income of $5 million compared with net income of $8 million in the same period last year.

The table below provides summary financial information for UNS Gas:

	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014			2013
	Millions of Dollars
Gas Revenues	$	23	$	22		$	62		$	73
Other Revenues	—		—			3			1
Total Operating Revenues	23		22			65			74
Purchased Gas Expense	12		12			42			42
Increase (Decrease) to Reflect PGA Recovery Treatment	—		(1		)	(8		)	(2		)
O&M	6		6			12			12
Depreciation and Amortization	2		2			5			4
Taxes Other Than Income Taxes	1		1			2			2
Total Operating Expenses	21		20			53			58
Operating Income	2		2			12			16
Other Expense	—		—			1			—
Interest Expense	2		2			3			3
Income Tax Expense	—		—			3			5
Net Income	$	—	$	—		$	5		$	8

The table below includes UNS Gas' therm sales and margin revenues for the second quarter of 2014 and 2013:

	Three Months Ended June 30,				Increase (Decrease)
	2014		2013		Amount			Percent(1)
Gas Retail Sales, Therms (in Millions):
Residential	10		9		1			11.1	%
Commercial	5		5		—			—	%
All Other	1		1		—			—	%
Total Gas Retail Sales	16		15		1			6.7	%
Negotiated Sales Program (NSP)	6		7		(1		)	(14.3	)%
Total Gas Sales	22		22		—			—	%
Retail Margin Revenues (in Millions):
Residential	$	7	$	7	$	—		—	%
Commercial	2		2		—			—	%
All Other	1		1		—			—	%
Total Retail Margin Revenues (Non-GAAP)(2)	10		10		—			—	%
Transport and NSP	4		4		—			—	%
Retail Fuel Revenues	9		8		1			12.5	%
Total Gas Revenues (GAAP)	$	23	$	22	$	1		4.5	%
Weather Data:
Heating Degree Days
Three Months Ended June 30,	541		480		61			12.7	%
10-Year Average	547		560		NM			NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

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⁽²⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

Retail therm sales in the second quarter of 2014 increased by 6.7% compared with the second quarter of 2013 due in part to a 12.7% increase in heating degree days. Despite the increase in retail therm sales, retail margin revenues were flat when compared with the second quarter of 2013.

UNS Gas supplies natural gas to some of its large transportation customers through an NSP. Approximately one half of the margin earned on these NSP sales is retained by UNS Gas, while the remainder benefits retail customers by reducing the gas commodity price through a credit to the PGA mechanism.

The table below includes UNS Gas’ therm sales and margin revenues for the first six months of 2014 and 2013:

	Six Months Ended June 30,				Increase (Decrease)
	2014		2013		Amount			Percent(1)
Gas Retail Sales, Therms (in Millions):
Residential	36		44		(8		)	(18.2	)%
Commercial	15		17		(2		)	(11.8	)%
All Other	5		5		—			—	%
Total Gas Retail Sales	56		66		(10		)	(15.2	)%
Negotiated Sales Program (NSP)	11		13		(2		)	(15.4	)%
Total Gas Sales	67		79		(12		)	(15.2	)%
Retail Margin Revenues (in Millions):
Residential	$	20	$	23	$	(3	)	(13.0	)%
Commercial	6		6		—			—	%
All Other	1		1		—			—	%
Total Retail Margin Revenues (Non-GAAP)(2)	27		30		(3		)	(10.0	)%
Transport and NSP	8		9		(1		)	(11.1	)%
Retail Fuel Revenues	27		34		(7		)	(20.6	)%
Total Gas Revenues (GAAP)	$	62	$	73	$	(11	)	(15.1	)%
Weather Data:
Heating Degree Days
Six Months Ended June 30,	2,263		2,668		(405		)	(15.2	)%
10-Year Average	2,653		2,643		NM			NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

⁽²⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

Retail therm sales in the first six months of 2014 declined by 15.2% when compared with the first six months of 2013 due to a 15.2% decrease in heating degree days. The lower retail therm sales contributed to a decrease in retail margin revenues of 10.0%, or $3 million, when compared with the first six months of 2013.

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FACTORS AFFECTING RESULTS OF OPERATIONS

Fair Value Measurements

See Note 12.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas expects operating cash flows to fund all of its construction expenditures during 2014. Sources of funding future capital expenditures could include existing cash balances, draws on the UNS Electric/UNS Gas Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.

Cash Flows and Capital Expenditures

The table below provides summary cash flow information for UNS Gas:

	Six Months Ended June 30,
	2014			2013
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	4		$	17
Investing Activities	(8		)	(8		)
Financing Activities	(11		)	(10		)
Net Decrease in Cash	(15		)	(1		)
Beginning Cash	33			31
Ending Cash	$	18		$	30

UNS Gas' operating cash flows during the first six months of 2014 were $13 million lower than the first six months of 2013 primarily due to the return of the over-collected PGA balance to customers and lower retail therm sales.

UNS Electric/UNS Gas Credit Agreement

At June 30, 2014, UNS Gas had no outstanding borrowings under the UNS Electric/UNS Gas Credit Agreement.

See UNS Electric, Liquidity and Capital Resources, UNS Electric/UNS Gas Credit Agreement.

Interest Rate Risk

See Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Contractual Obligations

There are no changes in UNS Gas' contractual obligations or other commercial commitments from those reported in our 2013 Annual Report on Form 10-K, other than the following changes in 2014:

• UNS Gas entered into new forward energy commitments with minimum payment obligations of $1 million in each of 2015 through 2017. See Note 6.

Dividends on Common Stock

UNS Gas paid dividends to UNS Energy, through UES, of $10 million in the first six months of 2014 and 2013. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The pending Settlement related to the Merger contains a condition restricting subsidiary dividend payments to UNS Energy. See UNS Energy, Outlook and Strategies.

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The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as 1) no default or event of default exists, and 2) it could incur additional debt under the debt incurrence test. At June 30, 2014, UNS Gas was in compliance with the terms of its note purchase agreement and had sufficient additional debt under the debt incurrence test to pay dividends.

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CRITICAL ACCOUNTING POLICIES

There have been no significant changes in our accounting policies from those disclosed in our 2013 Annual Report on Form 10-K.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In April 2014, the FASB issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.

In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UNS Energy and TEP are including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for UNS Energy or TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, estimates, expects, intends, plans, predicts, projects, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of UNS Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed therein. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis; and other parts of this report. These factors include: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of our pension and other retiree benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; cyber attacks or challenges to our information security; and the performance of TEP's generating plants.

ITEM 3. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

UNS Energy’s and TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 3 in our Annual Report on Form 10-K for the year ended December 31, 2013.

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ITEM 4. – CONTROLS AND PROCEDURES

UNS Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UNS Energy’s and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UNS Energy’s and TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by UNS Energy and TEP in the reports that they file or submit under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, UNS Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UNS Energy’s and TEP’s disclosure controls and procedures are effective.

While UNS Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UNS Energy’s or TEP’s internal control over financial reporting during the second quarter of 2014 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. – LEGAL PROCEEDINGS

See the legal proceedings described in Item 3. – Legal Proceedings in our 2013 Annual Report on Form 10-K and in Note 6 and in Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 6 and Item 2 are incorporated herein by reference.

ITEM 1A. – RISK FACTORS

The business and financial results of UNS Energy and TEP are subject to numerous risks and uncertainties. There are no significant changes to the risks and uncertainties reported in our 2013 Annual Report on Form 10-K.

ITEM 5. – OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES

The following table reflects the ratio of earnings to fixed charges for UNS Energy and TEP:

	Six Months Ended June 30, 2014	Twelve Months Ended June 30, 2014
UNS Energy	2.572	2.982
TEP	2.484	2.987

For purposes of this computation, earnings are defined as pre-tax earnings plus interest expense and amortization of debt discount and expense. Fixed charges are interest expense, including amortization of debt discount and expense.

ENVIRONMENTAL MATTERS

See Note 6.

Hazardous Air Pollutant Requirements

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

Navajo

Based on the MATS rules, Navajo may require mercury and particulate matter emission control equipment by April 2016. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which will be affected by final Best Available Retrofit Technology (BART) rules when issued. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each.

San Juan

TEP expects San Juan’s current emission controls to be adequate to comply with the MATS rules.

Four Corners

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

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Springerville Generating Station

Based on the MATS rules, Springerville Generating Station (Springerville) may require mercury emission control equipment by April 2016. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $1 million. Estimated costs are split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributed to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

Sundt Generating Station

TEP expects the MATS rules will have little effect on capital expenditures at Sundt.

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility 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. BART applies to plants built between August 1962 and August 1977. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.

Complying with the EPA’s BART findings, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.

Navajo

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

Among other things, the agreement calls for the shut-down of one unit or an equivalent reduction in emissions by 2020. The shutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install SCR or an equivalent technology on the remaining two units by 2030. As part of the agreement, the current owners have committed to cease their operation of conventional coal-fired generation at Navajo no later than December 2044. The Navajo Nation can continue operation after 2044 at its election. If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each. The EPA could issue their decision as early as 2014.

San Juan

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

In 2011, PNM filed a petition for review of, and a motion to stay, the FIP with the United States Court of Appeals for the Tenth Circuit (Tenth Circuit). In addition, the operator filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA's reconsideration and review by the Tenth Circuit. The State of New Mexico filed similar motions with the Tenth Circuit and the EPA. Several environmental groups were granted permission to join in opposition to PNM's petition to review in the Tenth Circuit. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP's five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Tenth Circuit denied PNM's and the State of New Mexico's motion for stay. Oral argument on the appeal was heard in October 2012.

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In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement (Settlement Agreement) that outlines an alternative to the FIP. The terms of the Settlement Agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of SNCR on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. The New Mexico Environmental Department (NMED) prepared a revision to the regional haze State Implementation Plan (SIP) incorporating the provisions of the Settlement Agreement, and in September 2013, the New Mexico Environmental Improvement Board approved the SIP revision. In May 2014, EPA proposed to approve the revised SIP and withdraw the existing FIP. The EPA is expected to make a final determination on the revised SIP in 2014.  TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $35 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. If San Juan Unit 2 is retired, TEP's coal-fired generating capacity would be reduced by 170 MW.

In connection with the implementation of the SIP revision and the retirement of San Juan Units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of the ownership in San Juan, as well as addressing the obligations of the exiting Participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The Participants have engaged a mediator to assist in facilitating the resolution of these matters among the owners. The owners of the affected units also may seek approvals of their utility commissions or governing boards. We are unable to predict the outcome of the negotiations and mediation.

On October 17, 2013, the Tenth Circuit ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously-filed motion to stay the FIP. The Tenth Circuit placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the Settlement Agreement is not implemented as contemplated, any party to the litigation may file a motion seeking to lift the abatement.

At June 30, 2014, the book value of TEP's share of San Juan Unit 2 was$112 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. TEP cannot predict the ultimate outcome of this matter.

Four Corners

In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on one unit by October 2016 and the remaining units by October 2017. In December 2013, APS (the operator) decided to shut down Units 1, 2, and 3 and install SCRs on Units 4 and 5. Under this scenario, the installation of SCR technology can be delayed until July 2018. TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $35 million. TEP's share of incremental annual operating costs for SCR is estimated at $2 million.

Springerville

The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018.

Sundt

In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule and developed a timeline to issue a federal implementation plan for emissions sources including Sundt Unit 4. While TEP does not agree that Sundt Unit 4 is subject to BART, it submitted a better-than-BART proposal in November 2013 which called for the elimination of coal as a fuel source at Sundt by the end of 2017. In June 2014, the EPA issued a final BART rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection (DSI) if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. TEP estimates that the cost to install SNCR and DSI would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the rule, TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

Greenhouse Gas Regulation

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

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In January 2014, the EPA published a re-proposed rule for new power plants. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

In June 2014, the EPA issued proposed carbon emission regulations for existing power plants called the Clean Power Plan. The Clean Power Plan targets a nation-wide reduction in carbon emissions of 30% by 2030. To achieve this goal, the proposed plan sets carbon emission rates for each state that must be achieved by an interim period of 2020-2029, with final rates by 2030. States can apply a variety of strategies to achieve the interim and final emission rates. Using 2012 as a baseline year, Arizona's carbon emission rate for 2030 represents a 52% reduction. The EPA expects to issue a final rule by June 2015, and under the current proposal, states must file implementation plans by June 2016 (or June 2017 for multi-state plans, with a possible one-year extension). UNS Energy cannot estimate the impact of the new proposed rule on its operations at this time.

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

Coal Combustion Residuals Regulations

The EPA is developing regulations for Coal Combustion Residuals (CCR) placed in landfills and surface impoundments (i.e. ponds).

In June 2010, the EPA issued a proposed rule presenting for public comment two approaches for regulating CCR: 1) as solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA); and 2) as hazardous waste under Subtitle C of RCRA. Both approaches would maintain an exception from regulation for beneficial use. In May 2014, EPA entered a consent decree agreeing to take final action on the proposed rule as it relates to regulation under Subtitle D of RCRA by December 2014.

If the final rule is structured similar to existing “municipal solid waste” rules, TEP’s ash disposal facility at Springerville would likely be in compliance with the requirements, however, upgrades could be required for future disposal. At Navajo and Four Corners, the ash that cannot be sold is land filled on site. These sites also could be required to upgrade. At San Juan, the ash that cannot be sold is returned to the mine. The proposed rule would not address mine placement of CCRs. Mine placement will be addressed through a separate rule-making under the oversight of the Department of Interior's Office of Surface Mining Reclamation and Enforcement.

If the final rule regulates CCR as a “hazardous waste”, in addition to the disposal facility upgrades discussed above, upgrades to handling and storage facilities at the plant sites would also be required.

TEP cannot determine the economic impact of this rule at this time.

ITEM 6. – EXHIBITS

See Exhibit Index.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

		UNS ENERGY CORPORATION
		(Registrant)
Date:	July 29, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President, Treasurer, and
		Chief Financial Officer
		TUCSON ELECTRIC POWER COMPANY
		(Registrant)
Date:	July 29, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer

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EXHIBIT INDEX

12(a)	—	Computation of Ratio of Earnings to Fixed Charges – UNS Energy.
12(b)	—	Computation of Ratio of Earnings to Fixed Charges – TEP.
31(a)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by David G. Hutchens.
31(b)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Kevin P. Larson.
31(c)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by David G. Hutchens.
31(d)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Kevin P. Larson.
**32(a)	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) - UNS Energy.
**32(b)	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) - TEP.
101	—	The following materials from UNS Energy’s and TEP’s Quarterly Report on Form 10-Q for the three and six-month periods ended June 30, 2014, formatted in XBRL (Extensible Business Reporting Language):
		(a)	UNS Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Balance Sheets, (v) Consolidated Statements of Changes in Stockholders’ Equity; and
		(b)	Notes to Consolidated Financial Statements.

(*) Previously filed as indicated and incorporated herein by reference.

** Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

72

EX-12.A

Exhibit 12a

UNS Energy Corporation

Computation of Ratio of Earnings to Fixed Charges

	6 Months Ended		12 Months Ended
	June 30,		June 30,		December 31,		December 31,		December 31,		December 31,		December 31,
	2014		2014		2013		2012		2011		2010		2009
	Thousands of Dollars
Net Income	$	57,829	$	139,344	$	127,478	$	90,919	$	109,975	$	112,984	$	105,901
Add:
Income Tax Expense	34,505		81,899		58,427		55,727		66,951		76,921		63,232
Interest Expense, net(1)	43,907		90,983		95,117		108,303		116,873		116,624		112,982
Estimated Interest Portion of Rental Expense (2)	452		932		959		691		926		240		345
Losses from Equity Investees	—		—		—		7		—		5,570		1,834
Total Earnings before Taxes and Fixed Charges	$	136,693	$	313,158	$	281,981	$	255,647	$	294,725	$	312,339	$	284,294
Fixed Charges:
Interest Expense (before deducting capitalized interest)(3)	$	52,703	$	104,087	$	100,844	$	110,456	$	120,626	$	119,211	$	115,284
Estimated Interest Portion of Rental Expense	452		932		959		691		926		240		345
Total Fixed Charges	$	53,155	$	105,019	$	101,803	$	111,147	$	121,552	$	119,451	$	115,629
Ratio of Earnings to Fixed Charges	2.572		2.982		2.770		2.300		2.425		2.615		2.459

⁽¹⁾  The ratios of earnings to fixed charges for the fiscal years ended 2012, 2011, 2010, and 2009 have been revised to exclude capitalized interest from the calculation of Earnings before Taxes and Fixed Charges. Capitalized interest was not material to the calculation of Earnings before Taxes and Fixed Charges or the Ratio of Earnings to Fixed Charges in prior periods. Interest on uncertain tax positions is included in Interest Expense.

⁽²⁾  The Estimated Interest Portion of Rental Expense is calculated by using our estimated incremental borrowing rate times the present value of projected operating lease payments.

⁽³⁾  Excludes recognition of Allowance for Borrowed Funds Used During Construction and Loss on Extinguishment of Debt.

EX-12.B

Exhibit 12b

Tucson Electric Power Company

Computation of Ratio of Earnings to Fixed Charges

	6 Months Ended		12 Months Ended
	June 30,		June 30,		December 31,		December 31,		December 31,		December 31,		December 31,
	2014		2014		2013		2012		2011		2010		2009
	Thousands of Dollars
Net Income	$	47,897	$	116,973	$	101,342	$	65,470	$	85,334	$	108,260	$	90,688
Add:
Income Tax Expense	28,080		73,157		47,986		39,109		52,000		59,936		54,220
Interest Expense, net(1)	36,552		76,423		80,793		91,295		93,786		93,465		89,715
Estimated Interest Portion of Rental Expense(2)	401		822		842		611		795		72		106
Total Earnings before Taxes and Fixed Charges	$	112,930	$	267,375	$	230,963	$	196,485	$	231,915	$	261,733	$	234,729
Fixed Charges:
Interest Expense (before deducting capitalized interest)(3)	$	45,058	$	88,701	$	85,591	$	93,077	$	95,859	$	95,345	$	91,467
Estimated Interest Portion of Rental Expense	401		822		842		611		795		72		106
Total Fixed Charges	$	45,459	$	89,523	$	86,433	$	93,688	$	96,654	$	95,417	$	91,573
Ratio of Earnings to Fixed Charges	2.484		2.987		2.672		2.097		2.399		2.743		2.563

⁽¹⁾  The ratios of earnings to fixed charges for the fiscal years ended 2012, 2011, 2010, and 2009 have been revised to exclude capitalized interest from the calculation of Earnings before Taxes and Fixed Charges. Capitalized interest was not material to the calculation of Earnings before Taxes and Fixed Charges or the Ratio of Earnings to Fixed Charges in prior periods. Interest on uncertain tax positions is included in Interest Expense.

⁽²⁾  The Estimated Interest Portion of Rental Expense is calculated by using our estimated incremental borrowing rate times the present value of projected operating lease payments.

⁽³⁾ Excludes recognition of Allowance for Borrowed Funds Used During Construction.

EX-31.A

Exhibit 31(a)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, David G. Hutchens, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2014, of UNS Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 29, 2014	/s/ David G. Hutchens
		David G. Hutchens
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Kevin P. Larson, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2014, of UNS Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 29, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

EX-31.C

Exhibit 31(c)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, David G. Hutchens, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2014, of Tucson Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 29, 2014	/s/ David G. Hutchens
		David G. Hutchens
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.D

Exhibit 31(d)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Kevin P. Larson, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2014, of Tucson Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 29, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32.A

Exhibit 32(a)

UNS ENERGY CORPORATION

_________________________________________________________

STATEMENTS OF CORPORATE OFFICERS

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

_________________________________________________________

Each of the undersigned, David G. Hutchens, President and Chief Executive Officer of UNS Energy Corporation (the “Company”), and Kevin P. Larson, Senior Vice President, Chief Financial Officer and Treasurer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

July 29, 2014

/s/ David G. Hutchens

David G. Hutchens

President and

Chief Executive Officer

(Principal Executive Officer)

UNS Energy Corporation

/s/ Kevin P. Larson

Kevin P. Larson

Senior Vice President,

Chief Financial Officer and Treasurer

(Principal Financial Officer)

UNS Energy Corporation

EX-32.B

Exhibit 32(b)

TUCSON ELECTRIC POWER COMPANY

 _________________________________________________________

STATEMENTS OF CORPORATE OFFICERS

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

 _________________________________________________________

Each of the undersigned, David G. Hutchens, President and Chief Executive Officer of Tucson Electric Power Company (the “Company”), and Kevin P. Larson, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

July 29, 2014

/s/ David G. Hutchens

David G. Hutchens

President and

Chief Executive Officer

(Principal Executive Officer)

Tucson Electric Power Company

/s/ Kevin P. Larson

Kevin P. Larson

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Tucson Electric Power Company

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

BUSINESS SEGMENTS (Tables)

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

Reconciling Adjustments of Income Statement Items in Consolidation

We disclose selected financial data for our reportable segments in the following tables:

	Reportable Segments
	TEP		UNS Electric		UNS Gas		Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
Three Months Ended June 30, 2014
Operating Revenues-External	$	318	$	47	$	22	$	—		$	—		$	387
Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
Income Before Income Taxes	61		6		—		—			—			67
Net Income	39		4		—		(1		)	—			42
Three Months Ended June 30, 2013
Operating Revenues-External	$	300	$	44	$	21	$	—		$	—		$	365
Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
Income Before Income Taxes	32		6		—		—			—			38
Net Income	31		4		—		—			—			35

	Reportable Segments
	TEP		UNS Electric		UNS Gas		Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
Six Months Ended June 30, 2014
Operating Revenues-External	$	569	87		64		$	—		$	—		$	720
Operating Revenues-Intersegment (1)	8		1		1		8			(18		)	—
Income Before Income Taxes	76		9		8		(1		)	—			92
Net Income	48		6		5		(1		)	—			58
Six Months Ended June 30, 2013
Operating Revenues-External	$	543	$	80	$	73	$	1		$	—		$	697
Operating Revenues-Intersegment (1)	9		1		1		8			(19		)	—
Income Before Income Taxes	35		9		13		—			—			57
Net Income	32		6		8		—			—			46

⁽¹⁾  Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

⁽²⁾  Other includes the UNS Energy and UES holding companies, Millennium, and UED.

XML

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

XML

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Environmental Matters) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014
Navajo [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	$ 1
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Estimated Capital Expenditure for Selective Catalytic Reduction	42	[1]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1	[1]
Better Than BART Agreement Year by which to Shut Down One Unit	2020
Better than BART Agreement, Year by which SCR Technology to be Installed	2030
Better than BART Agreement, Year by which Coal Fired Operation will Cease	2044
Estimated Capital Expenditure Related to Installation of Baghouses	43
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses	1
Jointly Owned Utility Plant, Proportionate Ownership Share	7.50%
Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	1
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Estimated Capital Expenditure for Selective Catalytic Reduction	35	[2]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2	[2]
Jointly Owned Utility Plant, Proportionate Ownership Share	7.00%
Springerville [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	5	[3]
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1	[3]
San Juan [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	35	[4]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	6
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1	[4]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Jointly Owned Utility Plant, Net Ownership Amount	112
San Juan [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	180
San Juan [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	200
Sundt [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12	[5]
Jointly Owned Utility Plant, Net Ownership Amount	27
Sundt [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5	[5]
Sundt [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	$ 6	[5]

[1] The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.

[2] In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

[3] Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

[4] The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

[5] In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

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BUSINESS SEGMENTS (Reconciliation of Income Statement Items from Segments to Consolidation) (Detail) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	$ 386,606,000		$ 365,217,000		$ 719,998,000		$ 697,358,000
Operating Revenues-Intersegment	0	[1]	0	[1]	0	[1]	0
Income Before Income Taxes	67,191,000		38,293,000		92,334,000		56,996,000
Net Income	42,354,000		34,618,000		57,829,000		45,963,000
Reconciling Adjustments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	0		0		0		0
Operating Revenues-Intersegment	(9,000,000)	[1]	(9,000,000)	[1]	(18,000,000)	[1]	(19,000,000)
Income Before Income Taxes	0		0		0		0
Net Income	0		0		0		0
TUCSON ELECTRIC POWER COMPANY | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	318,000,000		300,000,000		569,000,000		543,000,000
Operating Revenues-Intersegment	4,000,000	[1]	4,000,000	[1]	8,000,000	[1]	9,000,000
Income Before Income Taxes	61,467,000		32,439,000		75,977,000		35,000
Net Income	38,725,000		30,787,000		47,897,000		32,266,000
UNS Electric | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	47,000,000		44,000,000		87,000,000		80,000,000
Operating Revenues-Intersegment	0	[1]	0	[1]	1,000,000	[1]	1,000,000	[1]
Income Before Income Taxes	6,000,000		6,000,000		9,000,000		9,000,000
Net Income	4,000,000		4,000,000		6,000,000		6,000,000
UNS Gas | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	22,000,000		21,000,000		64,000,000		73,000,000
Operating Revenues-Intersegment	1,000,000	[1]	1,000,000	[1]	1,000,000	[1]	1,000,000
Income Before Income Taxes	0		0		8,000,000		13,000,000
Net Income	0		0		5,000,000		8,000,000
Other | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	0		0		0	[2]	1,000,000
Operating Revenues-Intersegment	4,000,000	[1]	4,000,000	[1]	8,000,000	[1],[2]	8,000,000
Income Before Income Taxes	0		0		(1,000,000)		0
Net Income	$ (1,000,000)		$ 0		$ (1,000,000)	[2]	$ 0

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

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

XML

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Assets
Cash Equivalent	$ 13	[1]	$ 14	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	11	[3]	7	[3]
Total Assets	49		45
Liabilities
Liabilities	(12)		(15)
Net Total Assets (Liability)	37		30
Energy Contracts [Member]
Liabilities
Derivative Liability	(5)	[3]	(7)	[3]
Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
Interest Rate Swap [Member]
Liabilities
Derivative Liability	(6)	[4]	(7)	[4]
TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	5	[3]	2	[3]
Total Assets	30		26
Liabilities
Liabilities	(10)		(10)
Net Total Assets (Liability)	20		16
TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(3)	[3]	(2)	[3]
TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(6)	[4]	(7)	[4]
Level 1 [Member]
Assets
Cash Equivalent	13	[1]	14	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	0	[3]	0	[3]
Total Assets	15		16
Liabilities
Liabilities	0		0
Net Total Assets (Liability)	15		16
Level 1 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	0	[3]	0	[3]
Total Assets	2		2
Liabilities
Liabilities	0		0
Net Total Assets (Liability)	2		2
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 2 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	5	[3]	3	[3]
Total Assets	28		25
Liabilities
Liabilities	(7)		(9)
Net Total Assets (Liability)	21		16
Level 2 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(6)	[4]	(7)	[4]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	2	[3]	1	[3]
Total Assets	25		23
Liabilities
Liabilities	(7)		(7)
Net Total Assets (Liability)	18		16
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(1)	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(6)	[4]	(7)	[4]
Level 3 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	6	[3]	4	[3]
Total Assets	6		4
Liabilities
Derivative Liability	(5)		(6)
Liabilities	(5)		(6)
Net Total Assets (Liability)	1		(2)
Level 3 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	(4)	[3]	(5)	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
Level 3 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Derivative Assets	3	[3]	1	[3]
Total Assets	3		1
Liabilities
Liabilities	(3)		(3)
Net Total Assets (Liability)	0		(2)
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(2)	[3]	(2)	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Netting [Member]
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Derivative Assets	(3)	[3],[5]	(5)	[3],[5]
Total Assets	(3)	[5]	(5)	[5]
Liabilities
Liabilities	3	[5]	5	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	3	[3],[5]	5	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4],[5]	0	[4],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Derivative Assets	(2)	[3],[5]	(1)	[3],[5]
Total Assets	(2)	[5]	(1)	[5]
Liabilities
Liabilities	2	[5]	1	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	2	[3],[5]	1	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4],[5]	0	[4],[5]
Net Fair Value [Member]
Assets
Cash Equivalent	13	[1]	14	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	8	[3]	2	[3]
Total Assets	46		40
Liabilities
Liabilities	(9)		(10)
Net Total Assets (Liability)	37		30
Net Fair Value [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	(2)	[3]	(2)	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(6)	[4]	(7)	[4]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	2	[1]	2	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	23	[2]	22	[2]
Derivative Assets	3	[3]	1	[3]
Total Assets	28		25
Liabilities
Liabilities	(8)		(9)
Net Total Assets (Liability)	20		16
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(1)	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	$ (6)	[4]	$ (7)	[4]

[1] Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

[2] Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

[3] Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.

[4] Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

[5] All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

XML

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

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

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

UNS Energy Corporation (UNS Energy) is a holding company that conducts its business through three regulated public utilities: Tucson Electric Power Company (TEP); UNS Electric, Inc. (UNS Electric); and UNS Gas, Inc. (UNS Gas) (collectively Regulated Utilities). References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.

We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K.

The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results. UNS Energy and TEP reclassified certain amounts in the financial statements to conform to current year presentation.

REVISION OF PRIOR PERIOD BALANCE SHEETS

UNS Energy and TEP revised their December 31, 2013 balance sheets to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2014, we adopted accounting guidance that:

• requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.

• impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.

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

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:

	UNS Energy
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Net Income	$	57,829		$	45,963
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	78,644			72,970
Amortization Expense	12,631			16,408
Depreciation and Amortization Recorded to Fuel and O&M Expense	3,977			3,516
Amortization of Deferred Debt-Related Costs included in Interest Expense	1,584			1,515
Provision for Retail Customer Bad Debts	1,194			936
Use of Renewable Energy Credits for Compliance	11,313			8,106
Deferred Income Taxes	36,320			36,644
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11,039		)
Pension and Retiree Expense	7,884			11,391
Pension and Retiree Funding	(5,974		)	(8,924		)
Share-Based Compensation Expense	1,859			1,390
Allowance for Equity Funds Used During Construction	(4,038		)	(2,463		)
LFCR Revenue	(7,654		)	—
Decrease to Reflect PPFAC/PGA Recovery	(21,437		)	(3,294		)
PPFAC Reduction - 2013 TEP Rate Order	—			3,000
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(22,766		)	(20,706		)
Materials and Fuel Inventory	(4,413		)	8,777
Accounts Payable	(5,875		)	(9,576		)
Income Taxes	(88		)	(15,980		)
Interest Accrued	1,305			(6,885		)
Taxes Other Than Income Taxes	3,721			490
Other	(8,259		)	15,413
Net Cash Flows – Operating Activities	$	137,757		$	147,652

	TEP
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Net Income	$	47,897		$	32,266
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	61,891			57,418
Amortization Expense	14,476			18,275
Depreciation and Amortization Recorded to Fuel and O&M Expense	3,406			2,987
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,285			1,216
Provision for Retail Customer Bad Debts	833			711
Use of Renewable Energy Credits for Compliance	9,884			7,414
Deferred Income Taxes	29,641			24,883
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(10,751		)
Pension and Retiree Expense	6,824			9,939
Pension and Retiree Funding	(5,522		)	(8,493		)
Share-Based Compensation Expense	1,496			1,108
Allowance for Equity Funds Used During Construction	(3,524		)	(1,763		)
LFCR Revenue	(6,121		)	—
Increase (Decrease) to Reflect PPFAC Recovery	(14,791		)	2,914
PPFAC Reduction - 2013 TEP Rate Order	—			3,000
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(35,498		)	(30,452		)
Materials and Fuel Inventory	(3,936		)	8,923
Accounts Payable	6,019			(11		)
Income Taxes	(6		)	(10,798		)
Interest Accrued	1,320			(6,886		)
Taxes Other Than Income Taxes	5,247			2,295
Other	(7,779		)	11,347
Net Cash Flows – Operating Activities	$	113,042		$	115,542

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UNS ENERGY EARNINGS PER SHARE (Tables)

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

Effects of Dilutive Common Stock on Weighted-Average Number of Shares

The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Thousands of Dollars
Numerator: Net Income	$	42,354	$	34,618	$	57,829	$	45,963
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,659		41,427		41,639		41,404
Fully Vested Deferred Stock Units	122		171		120		165
Total Weighted Average Common Stock Outstanding — Basic	41,781		41,598		41,759		41,569
Effect of Dilutive Securities:
Options and Stock Issuable Under Share-Based Compensation Plans	364		323		356		329
Total Weighted Average Common Stock Outstanding — Diluted	42,145		41,921		42,115		41,898

Shares of Common Stock Excluded from Computation of Diluted Earning Per Share

For the six months ended June 30, 2013, we excluded 12,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive.

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$ 11	[1]	$ 7	[1]
Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	6	[1]	4	[1]
Derivative Liability	(5)		(6)
Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	4	[2]	1	[2]
Derivative Liability	(4)	[2]	(4)	[2]
Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	2	[3]	3	[3]
Derivative Liability	(1)	[3]	(2)	[3]
Minimum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	23.90		26.54
Minimum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MMbtu	3.87		3.87
Gas volatility	21.01%		25.05%
Maximum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh	57.90		51.75
Maximum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MMbtu	4.57		4.32
Gas volatility	32.10%		35.07%
TUCSON ELECTRIC POWER COMPANY
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	5	[1]	2	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	3	[1]	1	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	2	[2]
Derivative Liability	(2)	[2]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Valuation Technique Option Model [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets			1	[2]
Derivative Liability			(3)	[2]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	1		1
Derivative Liability	$ (1)

[1] Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.

[2] TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.

[3] TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.

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

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

Schedule of Fair Value Measurements of Financial Assets and Liabilities

The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2014
	Millions of Dollars
Assets
Cash Equivalents(1)	$	13		$	13	$	—		$	—		$	—		$	13
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	23			—		23			—			—			23
Energy Contracts - Regulatory Recovery(3)	11			—		5			6			(3		)	8
Total Assets	49			15		28			6			(3		)	46
Liabilities
Energy Contracts - Regulatory Recovery(3)	(5		)	—		(1		)	(4		)	3			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(6		)	—		(6		)	—			—			(6		)
Total Liabilities	(12		)	—		(7		)	(5		)	3			(9		)
Net Total Assets (Liabilities)	$	37		$	15	$	21		$	1		$	—		$	37

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	14		$	14	$	—		$	—		$	—		$	14
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	7			—		3			4			(5		)	2
Total Assets	45			16		25			4			(5		)	40
Liabilities
Energy Contracts - Regulatory Recovery(3)	(7		)	—		(2		)	(5		)	5			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(15		)	—		(9		)	(6		)	5			(10		)
Net Total Assets (Liabilities)	$	30		$	16	$	16		$	(2	)	$	—		$	30

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2014
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	23			—		23			—			—			23
Energy Contracts - Regulatory Recovery(3)	5			—		2			3			(2		)	3
Total Assets	30			2		25			3			(2		)	28
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(1		)	(2		)	2			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(6		)	—		(6		)	—			—			(6		)
Total Liabilities	(10		)	—		(7		)	(3		)	2			(8		)
Net Total Assets (Liabilities)	$	20		$	2	$	18		$	—		$	—		$	20

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	2			—		1			1			(1		)	1
Total Assets	26			2		23			1			(1		)	25
Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)	—		—			(2		)	1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(10		)	—		(7		)	(3		)	1			(9		)
Net Total Assets (Liabilities)	$	16		$	2	$	16		$	(2	)	$	—		$	16

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

⁽³⁾  Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.

(4) Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

Financial Impact of Energy Contracts

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:

	UNS Energy					TEP
	Three Months Ended June 30,
	2014		2013			2014		2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	1	$	(9	)	$	2	$	(3	)

	UNS Energy				TEP
	Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	5	$	—	$	2	$	(1	)

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	June 30, 2014	December 31, 2013	June 30, 2014	December 31, 2013
Power Contracts GWh	1,933	1,583	976	779
Gas Contracts GBtu	63,546	33,371	27,176	9,615

Quantitative Information Regarding Unobservable Inputs

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:

		Fair Value at
		June 30, 2014						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	4	$	(4	)	Market price per MWh	$	23.90		-	$	57.90
Option Contracts(2)	Option model	2		(1		)	Market price per MMbtu	$	3.87		-	$	4.57
							Gas volatility	21.01		%	-	32.10		%
Level 3 Energy Contracts		$	6	$	(5	)
		Fair Value at
		December 31, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(3)	Market approach	$	1	$	(4	)	Market price per MWh	$	26.54		-	$	51.75
Option Contracts(4)	Option model	3		(2		)	Market price per MMbtu	$	3.87		-	$	4.32
							Gas volatility	25.05		%	-	35.07		%
Level 3 Energy Contracts		$	4	$	(6	)

⁽¹⁾  TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.

⁽²⁾  TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.

⁽³⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities at December 31, 2013.

⁽⁴⁾  TEP comprises less than $1 million of the option contract assets at December 31, 2013.

Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	UNS Energy			TEP
	Three Months Ended June 30, 2014
	Millions of Dollars
Balances at March 31, 2014	$	—		$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	3			2
Settlements	(2		)	—
Balances at June 30, 2014	$	1		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	3		$	3

	UNS Energy			TEP
	Six Months Ended June 30, 2014
	Millions of Dollars
Balances at December 31, 2013	$	(2	)	$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	5			1
Settlements	(2		)	1
Balances at June 30, 2014	$	1		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	2		$	1

	UNS Energy			TEP
	Three Months Ended June 30, 2013
	Millions of Dollars
Balances at March 31, 2013	$	(3	)	$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	—
Settlements	—			—
Balances at June 30, 2013	$	(5	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(4	)	$	—

	UNS Energy			TEP
	Six Months Ended June 30, 2013
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	(1		)
Settlements	2			—
Balances at June 30, 2013	$	(5	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(3	)	$	(1	)

Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments

The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:

		June 30, 2014				December 31, 2013
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Equity	Level 3	$	36	$	25	$	36	$	25
Liabilities:
Long-Term Debt
UNS Energy	Level 2	$	1,677	$	1,771	$	1,507	$	1,521
TEP	Level 2	1,372		1,435		1,223		1,214

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INCOME TAXES INCOME TAXES (Tables)

6 Months Ended

Jun. 30, 2014

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:

	UNS Energy						TEP
	Three Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	24		$	14		$	22		$	12
State Income Tax Expense, Net of Federal Deduction	3			2			3			2
Federal/State Tax Credits	(2		)	—			(2		)	—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
Other	—			(1		)	—			(1		)
Total Federal and State Income Tax Expense	$	25		$	4		$	23		$	2

	UNS Energy						TEP
	Six Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	32		$	20		$	27		$	12
State Income Tax Expense, Net of Federal Deduction	4			3			3			2
Federal/State Tax Credits	(2		)	—			(2		)	—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
Other	1			(1		)	—			—
Total Federal and State Income Tax Expense	$	35		$	11		$	28		$	3

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

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RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)

6 Months Ended

Jun. 30, 2014

Statement of Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:

	UNS Energy
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Three Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(349	)	$	(346	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	430			451
Realized Losses on Cash Flow Hedges, Net of Taxes	(664		)	(690		)
Amortization of SERP
Prior Service Cost and Net Loss	(40		)	(111		)	Operations and Maintenance
Tax Benefit	15			43
Amortization, Net of Taxes	(25		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(689	)	$	(758	)

	UNS Energy
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(702	)	$	(676	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	734			820
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,309		)	(1,255		)
Amortization of SERP
Prior Service Cost and Net Loss	(79		)	(222		)	Operations and Maintenance
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,358	)	$	(1,392	)

	TEP
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Three Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(293	)	$	(293	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	408			429
Realized Losses on Cash Flow Hedges, Net of Taxes	(630		)	(659		)
Amortization of SERP
Prior Service Cost and Net Loss	(40		)	(111		)	Other Expense
Tax Benefit	15			43
Amortization, Net of Taxes	(25		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(655	)	$	(727	)

	TEP
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(591	)	$	(575	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	692			781
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,240		)	(1,193		)
Amortization of SERP
Prior Service Cost and Net Loss	(79		)	(222		)	Other Expense
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,289	)	$	(1,330	)

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

[1] (1) In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.

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

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating Revenues
Electric Retail Sales	$ 302,975	$ 285,419	$ 527,545	$ 506,279
Electric Wholesale Sales	33,309	30,654	76,730	65,052
Gas Retail Sales	21,911	20,013	60,481	71,002
Other Revenue	28,411	29,131	55,242	55,025
Total Operating Revenues	386,606	365,217	719,998	697,358
Operating Expenses
Fuel	69,418	86,459	137,253	168,148
Purchased Energy	84,060	57,796	153,843	121,955
Transmission and Other PPFAC Recoverable Costs	6,142	4,521	12,670	7,707
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(12,517)	2,074	(21,437)	(3,294)
Total Fuel and Purchased Energy	147,103	150,850	282,329	294,516
Operations and Maintenance	91,621	95,143	185,057	185,043
Depreciation	39,563	36,671	78,644	72,970
Amortization	6,455	8,119	12,631	16,408
Taxes Other Than Income Taxes	14,942	13,631	29,750	27,723
Total Operating Expenses	299,684	304,414	588,411	596,660
Operating Income	86,922	60,803	131,587	100,698
Other Income (Deductions)
Interest Income	169	19	249	28
Other Income	2,538	1,734	4,680	3,502
Other Expense	(958)	(807)	(1,688)	(1,380)
Appreciation in Fair Value of Investments	624	94	879	1,133
Total Other Income (Deductions)	2,373	1,040	4,120	3,283
Interest Expense
Long-Term Debt	19,167	17,700	37,055	35,954
Capital Leases	3,925	6,249	7,846	12,498
Other Interest Expense	307	346	790	(47)
Interest Capitalized	(1,295)	(745)	(2,318)	(1,420)
Interest Expense	22,104	23,550	43,373	46,985
Income Before Income Taxes	67,191	38,293	92,334	56,996
Income Tax Expense	24,837	3,675	34,505	11,033
Net Income	42,354	34,618	57,829	45,963
Weighted-Average Shares of Common Stock Outstanding (000)
Basic (in shares)	41,781	41,598	41,759	41,569
Diluted (in shares)	42,145	41,921	42,115	41,898
Earnings Per Share
Basic (in dollars per share)	$ 1.01	$ 0.83	$ 1.38	$ 1.11
Diluted (in dollars per share)	$ 1.01	$ 0.83	$ 1.37	$ 1.10
Dividends Declared Per Share (usd per share)	$ 0.48	$ 0.435	$ 0.96	$ 0.87
TUCSON ELECTRIC POWER COMPANY
Operating Revenues
Electric Retail Sales	257,790	243,635	443,805	428,515
Electric Wholesale Sales	32,555	29,542	74,639	63,940
Other Revenue	31,273	31,086	58,687	59,559
Total Operating Revenues	321,618	304,263	577,131	552,014
Operating Expenses
Fuel	68,334	84,553	135,964	165,351
Purchased Energy	52,906	28,410	75,521	47,338
Transmission and Other PPFAC Recoverable Costs	3,552	1,730	7,461	2,595
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(13,061)	5,274	(14,791)	2,914
Total Fuel and Purchased Energy	111,731	119,967	204,155	218,198
Operations and Maintenance	79,772	82,011	161,117	159,835
Depreciation	31,080	28,861	61,891	57,418
Amortization	7,377	9,052	14,476	18,275
Taxes Other Than Income Taxes	12,005	10,939	23,840	22,108
Total Operating Expenses	241,965	250,830	465,479	475,834
Operating Income	79,653	53,433	111,652	76,180
Other Income (Deductions)
Interest Income	165	12	174	8
Other Income	2,187	1,270	4,099	2,438
Other Expense	(2,694)	(2,472)	(4,809)	(4,717)
Appreciation in Fair Value of Investments	624	94	879	1,133
Total Other Income (Deductions)	282	(1,096)	343	(1,138)
Interest Expense
Long-Term Debt	15,507	13,991	29,747	28,564
Capital Leases	3,925	6,249	7,846	12,498
Other Interest Expense	140	192	453	(168)
Interest Capitalized	(1,104)	(534)	(2,028)	(1,027)
Interest Expense	18,468	19,898	36,018	39,867
Income Before Income Taxes	61,467	32,439	75,977	35,175
Income Tax Expense	22,742	1,652	28,080	2,909
Net Income	$ 38,725	$ 30,787	$ 47,897	$ 32,266

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

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

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

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REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) (USD $)	1 Months Ended	6 Months Ended	1 Months Ended		6 Months Ended		10 Months Ended	1 Months Ended		6 Months Ended	1 Months Ended		12 Months Ended
	Apr. 30, 2014	Jun. 30, 2014	May 31, 2014 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2014 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Apr. 30, 2014 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2014 UNS Electric	May 31, 2014 UNS Electric	Jun. 30, 2014 UNS Electric	Apr. 30, 2014 May Through September [Member] TUCSON ELECTRIC POWER COMPANY	Apr. 30, 2014 October Through March [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2014 Scenario, Forecast [Member] TUCSON ELECTRIC POWER COMPANY
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
PPFAC Rate							0.0014				0.001	0.005
Mine Fire Cost Deferral					$ 10,000,000
Mine Fire Insurance Settlement Proceeds					8,000,000
Environmental Compliance Adjustor Rate			0.000049
Regulated Operating Revenue, Other													1,000,000
Transmission Cost Adjustor Rate								0.00114
Purchased Gas Adjustor Credit	0.10
Energy Efficiency Performance Incentive					2,000,000
Cap on increase in lost fixed cost recovery rate				1.00%
Lost Fixed Cost Recovery Requested			5,000,000						1,000,000
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism		$ 7,654,000			$ 6,121,000	$ 0				$ 2,000,000

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RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

6 Months Ended

Jun. 30, 2014

Statement of Comprehensive Income [Abstract]

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:

	UNS Energy
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Three Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(349	)	$	(346	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	430			451
Realized Losses on Cash Flow Hedges, Net of Taxes	(664		)	(690		)
Amortization of SERP
Prior Service Cost and Net Loss	(40		)	(111		)	Operations and Maintenance
Tax Benefit	15			43
Amortization, Net of Taxes	(25		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(689	)	$	(758	)

	UNS Energy
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(702	)	$	(676	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	734			820
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,309		)	(1,255		)
Amortization of SERP
Prior Service Cost and Net Loss	(79		)	(222		)	Operations and Maintenance
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,358	)	$	(1,392	)

	TEP
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Three Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(293	)	$	(293	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(602		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	408			429
Realized Losses on Cash Flow Hedges, Net of Taxes	(630		)	(659		)
Amortization of SERP
Prior Service Cost and Net Loss	(40		)	(111		)	Other Expense
Tax Benefit	15			43
Amortization, Net of Taxes	(25		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(655	)	$	(727	)

	TEP
Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(591	)	$	(575	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,198		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(143		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	692			781
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,240		)	(1,193		)
Amortization of SERP
Prior Service Cost and Net Loss	(79		)	(222		)	Other Expense
Tax Benefit	30			85
Amortization, Net of Taxes	(49		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,289	)	$	(1,330	)

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

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

Reclassification, Policy

REVISION OF PRIOR PERIOD BALANCE SHEETS

UNS Energy and TEP revised their December 31, 2013 balance sheets to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements.

Recently Adopted Accounting Pronouncements

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2014, we adopted accounting guidance that:

• requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.

• impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.

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

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

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SHARE-BASED COMPENSATION PLANS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

SHARE-BASED COMPENSATION PLANS

SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS

In May 2014, the UNS Energy Compensation Committee (Compensation Committee) granted 7,486 restricted stock units to non-employee directors at a grant date fair value, based on the grant date closing share price, of $60.11 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. We issue UNS Energy Common Stock (Common Stock) for the vested restricted stock units at the time elected by each of the non-employee directors based on certain eligibility requirements. These restricted stock units accrue dividend equivalents during and subsequent to the vesting period, which are distributed in shares of Common Stock at the same time as the related restricted stock units.

In February 2014, the Compensation Committee granted 16,910 restricted stock units to certain management employees at a grant date fair value, based on the grant date closing share price, of $60.39 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.

PERFORMANCE SHARES

In February 2014, the Compensation Committee granted 33,820 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $57.47 per share. Those awards will be paid out in Common Stock based on UNS Energy’s compound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period ended December 31, 2016. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date closing share price, of $60.39 per share and will be paid out in Common Stock based on cumulative net income for the three-year performance period ended December 31, 2016. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.

The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded share-based compensation expense of less than $1 million for the three months ended June 30, 2014 and June 30, 2013. For the six months ended June 30, 2014, UNS Energy recorded share-based compensation expense of $2 million, $1 million of which related to TEP. For the six months ended June 30, 2013, UNS Energy and TEP recorded share-based compensation expense of $1 million.

At June 30, 2014, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, of which $4 million are allocable to TEP, which will be recorded as compensation expense over the remaining vesting periods through February 2017. The completion of the Merger would result in accelerated vesting and expense recognition for these awards. See Note 2. At June 30, 2014, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.

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

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UNS ENERGY EARNINGS PER SHARE

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

UNS ENERGY EARNINGS PER SHARE

UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options or share-based compensation awards were exercised or converted into Common Stock. We excluded anti-dilutive contingently issuable shares from the calculation of diluted EPS.

The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	Thousands of Dollars
Numerator: Net Income	$	42,354	$	34,618	$	57,829	$	45,963
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,659		41,427		41,639		41,404
Fully Vested Deferred Stock Units	122		171		120		165
Total Weighted Average Common Stock Outstanding — Basic	41,781		41,598		41,759		41,569
Effect of Dilutive Securities:
Options and Stock Issuable Under Share-Based Compensation Plans	364		323		356		329
Total Weighted Average Common Stock Outstanding — Diluted	42,145		41,921		42,115		41,898

For the six months ended June 30, 2013, we excluded 12,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive.

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

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BUSINESS SEGMENTS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

BUSINESS SEGMENTS

BUSINESS SEGMENTS

We have three reportable segments regularly reviewed by our chief operating decision makers to evaluate performance and make operating decisions.

(1) TEP, a regulated electric utility and our largest subsidiary

(2) UNS Electric, a regulated electric utility

(3) UNS Gas, a regulated gas distribution utility

We disclose selected financial data for our reportable segments in the following tables:

	Reportable Segments
	TEP		UNS Electric		UNS Gas		Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
Three Months Ended June 30, 2014
Operating Revenues-External	$	318	$	47	$	22	$	—		$	—		$	387
Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
Income Before Income Taxes	61		6		—		—			—			67
Net Income	39		4		—		(1		)	—			42
Three Months Ended June 30, 2013
Operating Revenues-External	$	300	$	44	$	21	$	—		$	—		$	365
Operating Revenues-Intersegment(1)	4		—		1		4			(9		)	—
Income Before Income Taxes	32		6		—		—			—			38
Net Income	31		4		—		—			—			35

	Reportable Segments
	TEP		UNS Electric		UNS Gas		Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
Six Months Ended June 30, 2014
Operating Revenues-External	$	569	87		64		$	—		$	—		$	720
Operating Revenues-Intersegment (1)	8		1		1		8			(18		)	—
Income Before Income Taxes	76		9		8		(1		)	—			92
Net Income	48		6		5		(1		)	—			58
Six Months Ended June 30, 2013
Operating Revenues-External	$	543	$	80	$	73	$	1		$	—		$	697
Operating Revenues-Intersegment (1)	9		1		1		8			(19		)	—
Income Before Income Taxes	35		9		13		—			—			57
Net Income	32		6		8		—			—			46

⁽¹⁾  Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

⁽²⁾  Other includes the UNS Energy and UES holding companies, Millennium, and UED.

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REGULATORY MATTERS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of the Regulated Utilities.

The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales. The Merger with Fortis is subject to approval by the ACC. See Note 2. Additionally, the purchase of Gila River Generating Station Unit 3 (Gila River Unit 3) remains subject to FERC approval. See Note 7.

COST RECOVERY MECHANISMS

TEP Purchased Power and Fuel Adjustment Clause

In April 2014, the ACC approved a Purchased Power and Fuel Adjustment Clause (PPFAC) rate for TEP of 0.1 cents per kWh for the period May through September 2014 and 0.5 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was a credit of 0.14 cents per kWh for the period July 2013 through April 2014.

In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. At June 30, 2014, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.

TEP Environmental Compliance Adjustor

The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP expects to recognize ECA revenues of less than $1 million in 2014.

UNS Electric Transmission Cost Adjustor

The 2013 UNS Electric Rate Order provided a Transmission Cost Adjustor (TCA) that allows more timely recovery of transmission costs associated with serving retail customers. The TCA rate is adjusted annually based on information filed with the ACC each May. The TCA rate of 0.114 cents per kWh became effective in June 2014.

UNS Gas Purchased Gas Adjustor

In November of 2013, a Purchased Gas Adjustor (PGA) credit of 10 cents per therm became effective for UNS Gas. The credit expired in April 2014.

Energy Efficiency Standards

The Regulated Utilities are required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as a performance incentive. In the first half of 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Sales in the UNS Energy and TEP income statements.

Lost Fixed Cost Recovery Mechanism

The Lost Fixed Cost Recovery (LFCR) mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved energy efficiency programs and distributed generation targets. During separate rate case proceedings in 2013, the ACC authorized LFCR mechanisms for TEP and UNS Electric, subject to a year-over-year cap of 1% of each company’s respective total retail revenues.

TEP and UNS Electric filed their first LFCR reports with the ACC in May 2014. TEP requested recovery of approximately $5 million and UNS Electric requested recovery of approximately $1 million. The LFCR rates are expected to go into effect in August 2014 for TEP and in September 2014 for UNS Electric.

TEP and UNS Electric recorded LFCR revenues of $6 million and $2 million, respectively, in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. We recognize LFCR revenue when verifiable regardless of when the lost retail kWh sales occur. LFCR revenue is included in Electric Retail Sales in the income statements.

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In April 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.

In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.

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SUPPLEMENTAL CASH FLOW INFORMATION

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:

	UNS Energy
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Net Income	$	57,829		$	45,963
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	78,644			72,970
Amortization Expense	12,631			16,408
Depreciation and Amortization Recorded to Fuel and O&M Expense	3,977			3,516
Amortization of Deferred Debt-Related Costs included in Interest Expense	1,584			1,515
Provision for Retail Customer Bad Debts	1,194			936
Use of Renewable Energy Credits for Compliance	11,313			8,106
Deferred Income Taxes	36,320			36,644
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11,039		)
Pension and Retiree Expense	7,884			11,391
Pension and Retiree Funding	(5,974		)	(8,924		)
Share-Based Compensation Expense	1,859			1,390
Allowance for Equity Funds Used During Construction	(4,038		)	(2,463		)
LFCR Revenue	(7,654		)	—
Decrease to Reflect PPFAC/PGA Recovery	(21,437		)	(3,294		)
PPFAC Reduction - 2013 TEP Rate Order	—			3,000
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(22,766		)	(20,706		)
Materials and Fuel Inventory	(4,413		)	8,777
Accounts Payable	(5,875		)	(9,576		)
Income Taxes	(88		)	(15,980		)
Interest Accrued	1,305			(6,885		)
Taxes Other Than Income Taxes	3,721			490
Other	(8,259		)	15,413
Net Cash Flows – Operating Activities	$	137,757		$	147,652

	TEP
	Six Months Ended June 30,
	2014			2013
	Thousands of Dollars
Net Income	$	47,897		$	32,266
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	61,891			57,418
Amortization Expense	14,476			18,275
Depreciation and Amortization Recorded to Fuel and O&M Expense	3,406			2,987
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,285			1,216
Provision for Retail Customer Bad Debts	833			711
Use of Renewable Energy Credits for Compliance	9,884			7,414
Deferred Income Taxes	29,641			24,883
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(10,751		)
Pension and Retiree Expense	6,824			9,939
Pension and Retiree Funding	(5,522		)	(8,493		)
Share-Based Compensation Expense	1,496			1,108
Allowance for Equity Funds Used During Construction	(3,524		)	(1,763		)
LFCR Revenue	(6,121		)	—
Increase (Decrease) to Reflect PPFAC Recovery	(14,791		)	2,914
PPFAC Reduction - 2013 TEP Rate Order	—			3,000
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(35,498		)	(30,452		)
Materials and Fuel Inventory	(3,936		)	8,923
Accounts Payable	6,019			(11		)
Income Taxes	(6		)	(10,798		)
Interest Accrued	1,320			(6,886		)
Taxes Other Than Income Taxes	5,247			2,295
Other	(7,779		)	11,347
Net Cash Flows – Operating Activities	$	113,042		$	115,542

NON-CASH TRANSACTIONS

In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase lease interests in April 2015. See Note 5.

In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction.

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PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY

6 Months Ended

Jun. 30, 2014

Other Commitments [Abstract]

OTHER COMMITMENTS

PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY

In December 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to FERC approval and other closing conditions.

In December 2013, UNS Electric filed an application for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3. The application is still pending before the ACC.

In June 2014, TEP provided a letter of credit (LOC) for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. The seller is entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the purchase agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled.

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

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

DEBT AND CAPITAL LEASE OBLIGATIONS

We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2013 Annual Report on Form 10-K.

TEP SPRINGERVILLE COAL HANDLING FACILITIES CAPITAL LEASE PURCHASE COMMITMENT

In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, TEP recorded, in April of 2014, an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment.

TEP previously agreed with Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at June 30, 2014.

2014 TEP UNSECURED NOTES ISSUED

In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may call the debt prior to September 15, 2043, with a make-whole premium plus accrued interest. After September 15, 2043, TEP may call the debt at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the revolving credit facility, with the remaining proceeds to be applied to general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.

TEP CREDIT AGREEMENT

The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility and an $82 million LOC facility to support tax-exempt bonds. As of June 30, 2014, there is $184 million available under the revolving credit facility. The TEP Credit Agreement expires in November 2016. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.

TEP provided, in the second quarter of 2014, a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 7.

COVENANT COMPLIANCE

At June 30, 2014, we were in compliance with the terms of our loan and credit agreements.

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS

UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas. In addition to those reported in our 2013 Annual Report on Form 10-K, UNS Energy entered into the following long-term commitments through June 30, 2014:

	UNS Energy Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, including Transportation	$	—	$	9	$	9	$	9	$	8	$	8	$	43
Purchased Power	—		23		—		—		—		—		23
Capital Lease Obligations(1)	—		120		—		—		—		—		120
Total Purchase Commitments	$	—	$	152	$	9	$	9	$	8	$	8	$	186

TEP entered into the following long-term commitments:

	TEP Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	—	$	8	$	8	$	8	$	8	$	8	$	40
Purchased Power	—		15		—		—		—		—		15
Capital Lease Obligations(1)	—		120		—		—		—		—		120
Total Purchase Commitments	$	—	$	143	$	8	$	8	$	8	$	8	$	175

⁽¹⁾  In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.

UNS ENERGY CONTINGENCIES

In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a Settlement in which the Regulated Utilities agreed, contingent upon completion of the Merger, to provide credits on retail customers' bills totaling $30 million over five years. See Note 2.

TEP CONTINGENCIES

Planned Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.

Claim Related to San Juan Generating Station

San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The joint participants have agreed to have the matter stayed until August 2014 in furtherance of settlement talks.

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.

In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. The New Mexico Taxation and Revenue Department and APS started settlement negotiations in July 2014. TEP cannot predict the outcome or timing of resolution of this claim.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $20 million at June 30, 2014 and $18 million at December 31, 2013.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows us to pass through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Discontinued Transmission Project

TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. TEP and UNS Electric plan to keep the path approved in the line siting matter in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery.

Performance Guarantees

The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. As of June 30, 2014, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements expire in 2016 through 2046.

UNS ELECTRIC CONTINGENCIES

Planned Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.

ENVIRONMENTAL MATTERS

Environmental Regulation

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.

Hazardous Air Pollutant Requirements

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATS) rules, additional emission control equipment will be required by April 2015. TEP has received an extension until April 2016 to comply with the MATS rules at Springerville. The operator of Navajo has also received an extension until April 2016. TEP's share of the estimated costs to comply with the MATS rules include the following:

Estimated Mercury Emissions Control Costs:	Navajo		Four Corners		Springerville(1)
	Millions of Dollars
Capital Expenditures	$	1	$	1	$	5
Annual O&M Expenses	1		1		1

⁽¹⁾ Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

TEP expects Sundt and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules.

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.

In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the BART rules apply to plants built prior to Springerville. TEP cannot predict the ultimate outcome of these matters.

TEP's estimated costs involved in meeting these rules are:

Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital Expenditures	$	42	$	35	$	35	$	12
Annual O&M Expenses	1		1		2		5-6

⁽¹⁾ The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾ The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

⁽³⁾ In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾ In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:

	Pension Benefits						Other Retiree Benefits
	Three Months Ended June 30,
	2014			2013			2014		2013
	Millions of Dollars
Service Cost	$	2		$	3		$	1	$	1
Interest Cost	5			4			—		1
Expected Return on Plan Assets	(5		)	(5		)	—		—
Actuarial Loss Amortization	1			2			—		—
Net Periodic Benefit Cost	$	3		$	4		$	1	$	2

	Pension Benefits						Other Retiree Benefits
	Six Months Ended June 30,
	2014			2013			2014		2013
	Millions of Dollars
Service Cost	$	5		$	6		$	2	$	2
Interest Cost	9			8			1		1
Expected Return on Plan Assets	(11		)	(10		)	—		—
Actuarial Loss Amortization	2			4			—		—
Net Periodic Benefit Cost	$	5		$	8		$	3	$	3

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

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

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INCOME TAXES INCOME TAXES

6 Months Ended

Jun. 30, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:

	UNS Energy						TEP
	Three Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	24		$	14		$	22		$	12
State Income Tax Expense, Net of Federal Deduction	3			2			3			2
Federal/State Tax Credits	(2		)	—			(2		)	—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
Other	—			(1		)	—			(1		)
Total Federal and State Income Tax Expense	$	25		$	4		$	23		$	2

	UNS Energy						TEP
	Six Months Ended June 30,
	2014			2013			2014			2013
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	32		$	20		$	27		$	12
State Income Tax Expense, Net of Federal Deduction	4			3			3			2
Federal/State Tax Credits	(2		)	—			(2		)	—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	—			(11		)	—			(11		)
Other	1			(1		)	—			—
Total Federal and State Income Tax Expense	$	35		$	11		$	28		$	3

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.

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COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Unrecorded Unconditional Purchase Obligations Disclosure

In addition to those reported in our 2013 Annual Report on Form 10-K, UNS Energy entered into the following long-term commitments through June 30, 2014:

	UNS Energy Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, including Transportation	$	—	$	9	$	9	$	9	$	8	$	8	$	43
Purchased Power	—		23		—		—		—		—		23
Capital Lease Obligations(1)	—		120		—		—		—		—		120
Total Purchase Commitments	$	—	$	152	$	9	$	9	$	8	$	8	$	186

TEP entered into the following long-term commitments:

	TEP Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	—	$	8	$	8	$	8	$	8	$	8	$	40
Purchased Power	—		15		—		—		—		—		15
Capital Lease Obligations(1)	—		120		—		—		—		—		120
Total Purchase Commitments	$	—	$	143	$	8	$	8	$	8	$	8	$	175

⁽¹⁾  In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.

Schedule of Environmental Loss Contingencies by Site

TEP's estimated costs involved in meeting these rules are:

Estimated NOx Emissions Control Costs:	Navajo (1)		San Juan (2)		Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital Expenditures	$	42	$	35	$	35	$	12
Annual O&M Expenses	1		1		2		5-6

⁽¹⁾ The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾ The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

⁽³⁾ In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾ In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

TEP's share of the estimated costs to comply with the MATS rules include the following:

Estimated Mercury Emissions Control Costs:	Navajo		Four Corners		Springerville(1)
	Millions of Dollars
Capital Expenditures	$	1	$	1	$	5
Annual O&M Expenses	1		1		1

⁽¹⁾ Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

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

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (UNS & TEP Contingencies) (Detail) (USD $) In Millions, unless otherwise specified							6 Months Ended
	Jun. 30, 2014 San Juan [Member]	Jun. 30, 2014 Tucson to Nogales [Member] mi	Jun. 30, 2014 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2014 TUCSON ELECTRIC POWER COMPANY San Juan [Member]	Jun. 30, 2014 TUCSON ELECTRIC POWER COMPANY Four Corner [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY Tucson to Nogales [Member]	Jun. 30, 2014 TUCSON ELECTRIC POWER COMPANY Tucson to Nogales [Member]	Jun. 30, 2014 Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member] TUCSON ELECTRIC POWER COMPANY San Juan [Member]	Jun. 30, 2014 Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member] TUCSON ELECTRIC POWER COMPANY San Juan [Member]	Jun. 30, 2014 Assessment for Coal Severance Tax, Coal Supplier [Member] TUCSON ELECTRIC POWER COMPANY Four Corner [Member]	Jun. 30, 2014 Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member] TUCSON ELECTRIC POWER COMPANY Four Corner [Member]	Jun. 30, 2014 Total Bill Credit Refunds Over 5 Years [Member]
Commitments And Contingencies [Line Items]
Customer Bill Credits Required Per Merger Settlement Agreement Subject to Regulatory Approval													$ 30
Percentage of ownership in generating station					50.00%	7.00%
Percentage Of Ownership In Generating Units	20.00%
Estimate of Possible Loss Contingency									5	1	30	1
TEP accrued an estimated loss related to Four Corners Generating Station						1
TEP's share of reclamation costs at expiration dates of the coal supply agreements			44
TEP's recorded obligations for final mine reclamation costs			20	18
Transmission line from Tucson to Nogales		60
Transmission Line, in KV		345
Asset Impairment Charges							5
Regulatory Assets								$ 5

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

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PENDING MERGER WITH FORTIS

6 Months Ended

Jun. 30, 2014

Business Combinations [Abstract]

PENDING MERGER WITH FORTIS INC.

PENDING MERGER WITH FORTIS

On December 11, 2013, UNS Energy announced that it had entered into an Agreement and Plan of Merger (Merger), subject to shareholder and required regulatory approvals, to be acquired by Fortis Inc. (Fortis) for $60.25 per share of Common Stock in cash. Following the Merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Boards of Directors of each of UNS Energy and Fortis have approved the Merger.

The following additional approvals have been received:

• In March 2014, UNS Energy's shareholders approved the Merger;

• In April 2014, the Federal Energy Regulatory Commission (FERC) approved the Merger;

• In May 2014, the Committee on Foreign Investment in the United States concluded its review determining there are no unresolved national security concerns with respect to the Merger;

• In June 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and

• In July 2014, the Federal Communications Commission approved UNS Energy’s FCC license transfer of control applications with respect to the Merger.

The final regulatory approval necessary to complete the Merger is approval by the Arizona Corporation Commission (ACC). In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a settlement (Settlement) in which the parties agree that the Merger is in the public interest and recommend approval by the ACC, subject to certain conditions. Those conditions include, but are not limited to, the following:

• UNS Energy shall provide credits on the Regulated Utilities retail customers' bills totaling $30 million over five years; $10 million in year one and $5 million annually in years two through five. The monthly bill credits will be applied each year from October through March. If the Merger closes by the end of September 2014, the bill credits will commence on October 1, 2014;

• UNS Energy and the Regulated Utilities will adopt certain ring-fencing and corporate governance provisions;

• Dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014; and

• Fortis shall make an equity investment totaling $220 million through UNS Energy into the Regulated Utilities following closing of the Merger. However, if the Merger closes after September 30, 2014, the equity investment may be made into UNS Energy to retire debt.

The Settlement is subject to the review and approval of the ACC, which could approve, reject, or require modifications to the Settlement as a condition of approval of the Merger. Hearings before an ACC administrative law judge on the Settlement concluded on June 17, 2014. The Settlement requests that the ACC issue an order approving the Settlement no later than September 18, 2014.

The completion of the Merger is also subject to the absence of any injunction, order, or other law prohibiting the Merger.

If the Merger is approved by the ACC in September 2014 as requested by the parties to the Settlement Agreement, we expect the Merger to close by the end of September 2014. Upon completion of the Merger, UNS Energy expects to record approximately $19 million of merger-related expenses including investment banker fees, legal fees, and accelerated expenses for certain share-based compensation awards. TEP would record approximately $15 million as its allocated share of these merger-related expenses. See Note 9.

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

XML

EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

Components of Net Periodic Benefit Cost

UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:

	Pension Benefits						Other Retiree Benefits
	Three Months Ended June 30,
	2014			2013			2014		2013
	Millions of Dollars
Service Cost	$	2		$	3		$	1	$	1
Interest Cost	5			4			—		1
Expected Return on Plan Assets	(5		)	(5		)	—		—
Actuarial Loss Amortization	1			2			—		—
Net Periodic Benefit Cost	$	3		$	4		$	1	$	2

	Pension Benefits						Other Retiree Benefits
	Six Months Ended June 30,
	2014			2013			2014		2013
	Millions of Dollars
Service Cost	$	5		$	6		$	2	$	2
Interest Cost	9			8			1		1
Expected Return on Plan Assets	(11		)	(10		)	—		—
Actuarial Loss Amortization	2			4			—		—
Net Periodic Benefit Cost	$	5		$	8		$	3	$	3

XML

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

XML

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

6 Months Ended

Jun. 30, 2014

Text Block [Abstract]

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2014
	Millions of Dollars
Assets
Cash Equivalents(1)	$	13		$	13	$	—		$	—		$	—		$	13
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	23			—		23			—			—			23
Energy Contracts - Regulatory Recovery(3)	11			—		5			6			(3		)	8
Total Assets	49			15		28			6			(3		)	46
Liabilities
Energy Contracts - Regulatory Recovery(3)	(5		)	—		(1		)	(4		)	3			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(6		)	—		(6		)	—			—			(6		)
Total Liabilities	(12		)	—		(7		)	(5		)	3			(9		)
Net Total Assets (Liabilities)	$	37		$	15	$	21		$	1		$	—		$	37

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	14		$	14	$	—		$	—		$	—		$	14
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	7			—		3			4			(5		)	2
Total Assets	45			16		25			4			(5		)	40
Liabilities
Energy Contracts - Regulatory Recovery(3)	(7		)	—		(2		)	(5		)	5			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(15		)	—		(9		)	(6		)	5			(10		)
Net Total Assets (Liabilities)	$	30		$	16	$	16		$	(2	)	$	—		$	30

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2014
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	23			—		23			—			—			23
Energy Contracts - Regulatory Recovery(3)	5			—		2			3			(2		)	3
Total Assets	30			2		25			3			(2		)	28
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(1		)	(2		)	2			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(6		)	—		(6		)	—			—			(6		)
Total Liabilities	(10		)	—		(7		)	(3		)	2			(8		)
Net Total Assets (Liabilities)	$	20		$	2	$	18		$	—		$	—		$	20

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	2			—		1			1			(1		)	1
Total Assets	26			2		23			1			(1		)	25
Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)	—		—			(2		)	1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(10		)	—		(7		)	(3		)	1			(9		)
Net Total Assets (Liabilities)	$	16		$	2	$	16		$	(2	)	$	—		$	16

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

⁽³⁾  Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.

(4) Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

DERIVATIVE INSTRUMENTS

We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA.

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.

We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. In the first half of 2013, we also used this pricing model to value our power options.

We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.

Our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our price curves monthly.

Cash Flow Hedges

We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 14. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million for UNS Energy and TEP.

Financial Impact of Energy Contracts

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:

	UNS Energy					TEP
	Three Months Ended June 30,
	2014		2013			2014		2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	1	$	(9	)	$	2	$	(3	)

	UNS Energy				TEP
	Six Months Ended June 30,
	2014		2013		2014		2013
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities	$	5	$	—	$	2	$	(1	)

Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At June 30, 2014, UNS Energy and TEP have energy contracts that will settle through the second quarter of 2017.

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	June 30, 2014	December 31, 2013	June 30, 2014	December 31, 2013
Power Contracts GWh	1,933	1,583	976	779
Gas Contracts GBtu	63,546	33,371	27,176	9,615

Level 3 Fair Value Measurements

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:

		Fair Value at
		June 30, 2014						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	4	$	(4	)	Market price per MWh	$	23.90		-	$	57.90
Option Contracts(2)	Option model	2		(1		)	Market price per MMbtu	$	3.87		-	$	4.57
							Gas volatility	21.01		%	-	32.10		%
Level 3 Energy Contracts		$	6	$	(5	)
		Fair Value at
		December 31, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(3)	Market approach	$	1	$	(4	)	Market price per MWh	$	26.54		-	$	51.75
Option Contracts(4)	Option model	3		(2		)	Market price per MMbtu	$	3.87		-	$	4.32
							Gas volatility	25.05		%	-	35.07		%
Level 3 Energy Contracts		$	4	$	(6	)

⁽¹⁾  TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.

⁽²⁾  TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.

⁽³⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities at December 31, 2013.

⁽⁴⁾  TEP comprises less than $1 million of the option contract assets at December 31, 2013.

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC or PGA mechanisms and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	UNS Energy			TEP
	Three Months Ended June 30, 2014
	Millions of Dollars
Balances at March 31, 2014	$	—		$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	3			2
Settlements	(2		)	—
Balances at June 30, 2014	$	1		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	3		$	3

	UNS Energy			TEP
	Six Months Ended June 30, 2014
	Millions of Dollars
Balances at December 31, 2013	$	(2	)	$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	5			1
Settlements	(2		)	1
Balances at June 30, 2014	$	1		$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	2		$	1

	UNS Energy			TEP
	Three Months Ended June 30, 2013
	Millions of Dollars
Balances at March 31, 2013	$	(3	)	$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	—
Settlements	—			—
Balances at June 30, 2013	$	(5	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(4	)	$	—

	UNS Energy			TEP
	Six Months Ended June 30, 2013
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	(1		)
Settlements	2			—
Balances at June 30, 2013	$	(5	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(3	)	$	(1	)

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to the Regulated Utilities; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.

Material adverse changes could trigger credit risk-related contingent features. At June 30, 2014, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $25 million for UNS Energy and $19 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $25 million for UNS Energy and $19 million for TEP.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:

• The carrying amounts of our current maturities of long-term debt and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.

• For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.

• For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:

		June 30, 2014				December 31, 2013
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Equity	Level 3	$	36	$	25	$	36	$	25
Liabilities:
Long-Term Debt
UNS Energy	Level 2	$	1,677	$	1,771	$	1,507	$	1,521
TEP	Level 2	1,372		1,435		1,223		1,214