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, 2013

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 17, 2013, 41,483,662 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of July 17, 2013, 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	v
Reports of Independent Registered Public Accounting Firm	1
PART I
Item 1. – Financial Statements	3
UNS Energy Corporation	3
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	4
Condensed Consolidated Statements of Cash Flows	5
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statement of Changes in Stockholders’ Equity	8
Tucson Electric Power Company	9
Condensed Consolidated Statements of Income	9
Condensed Consolidated Statements of Comprehensive Income	10
Condensed Consolidated Statements of Cash Flows	11
Condensed Consolidated Balance Sheets	12
Condensed Consolidated Statement of Changes in Stockholder’s Equity	14
Notes to Condensed Consolidated Financial Statements - Unaudited	15
Note 1. Financial Statement Presentation	15
Note 2. Regulatory Matters	16
Note 3. Business Segments	18
Note 4. Commitments, Contingencies, and Environmental Matters	19
Note 5. Debt and Credit Facilities	24
Note 6. Income Taxes	24
Note 7. Employee Benefit Plans	26
Note 8. Share-Based Compensation Plans	26
Note 9. UNS Energy Earnings Per Share	27
Note 10. Supplemental Cash Flow Information	28
Note 11. Fair Value Measurements and Derivative Instruments	29
Note 12. Changes in Accumulated Other Comprehensive Income by Component	35
Note 13. Recently Issued Accounting Pronouncement	37
Note 14. Review by Independent Registered Public Accounting Firm	37
Item  2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
UNS Energy Corporation	38
Overview of Consolidated Business	38
Outlook and Strategies	38
Results of Operations	39
Liquidity and Capital Resources	40
Tucson Electric Power Company	43
Results of Operations	43
Factors Affecting Results of Operations	51
Liquidity and Capital Resources	55
UNS Gas	58
Results of Operations	58
Factors Affecting Results of Operations	61
Liquidity and Capital Resources	62

iii

UNS Electric	64
Results of Operations	64
Factors Affecting Results of Operations	66
Liquidity and Capital Resources	68
Critical Accounting Estimates	69
Recently Issued Accounting Pronouncement	70
Safe Harbor for Forward-Looking Statements	70
PART II – OTHER INFORMATION
Item 1. – Legal Proceedings	70
Item 1A. – Risk Factors	71
Item 2. – Unregistered Sale of Equity Securities and Use of Proceeds	72
Item 3. – Quantitative and Qualitative Disclosures about Market Risk	72
Item 4. – Controls and Procedures	72
Item 5. – Other Information	72
Ratio of Earnings to Fixed Charges	72
Environmental Matters	73
Item 6. Exhibits	74
Signatures	75
Exhibit Index	76

iv

DEFINITIONS

The abbreviations and acronyms used in the 2013second quarter report on Form 10-Q are defined below:

1992 Mortgage	TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York Mellon, successor trustee, as supplemented
2010 TEP Reimbursement Agreement	Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2010 UNS Electric Rate Order	A rate order issued by the ACC resulting in a new rate structure for UNS Electric, effective September 1, 2010
2013 TEP Rate Order	A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013
ACC	Arizona Corporation Commission
AOCI	Accumulated Other Comprehensive Income
APS	Arizona Public Service Company
ARO	Asset Retirement Obligation
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)
Capacity	The ability to produce power; the most power a unit can produce or the maximum that can be taken under a contract, measured in megawatts
CC&N	Certificate of Convenience and Necessity
Common Stock	UNS Energy Corporation’s common stock, without par value
Company	UNS Energy Corporation and its subsidiaries
Convertible Senior Notes	UNS Energy Corporation’s 4.5% Convertible Senior Notes
DSM	Demand Side Management
ECA	Environmental Compliance Adjustor
Electric EE Standards	Electric Energy Efficiency Standards
Energy	The amount of power produced over a given period of time measured in megawatt-hours
EPA	Environmental Protection Agency
EPS	Earnings Per Share
ESP	Electric Service Providers
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
FVRB	Fair Value Rate Base
Four Corners	Four Corners Generating Station
GAAP	Generally Accepted Accounting Principles
Gas EE Standards	Gas Energy Efficiency Standards
GBtu	Billion British thermal units
GWh	Gigawatt-hour(s)
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
IRS	Internal Revenue Service
kV	Kilo-volt

v

kWh	Kilowatt-hour(s)
LFCR	Lost Fixed Cost Recovery Mechanism
LOC	Letter of Credit
LIBOR	London Interbank Offered Rate
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation
MMBtu	Million British thermal units
Mortgage Bonds	Mortgage Bonds issued under the 1992 Mortgage
MW	Megawatt(s)
MWh	Megawatt-hour(s)
Navajo	Navajo Generating Station
Net Cash Flows after Capital Expenditures	A non-GAAP financial measure that compares capital expenditures relative to cash flows from operating activities
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations	A non-GAAP financial measure that compares capital expenditures and required payments on capital lease obligations relative to cash flows from operating activities
NSP	Negotiated Sales Program. A program in which UNS Gas sells natural gas to some of its large transportation customers.
NTUA	Navajo Tribal Utility Authority
NOx	Nitrogen Oxide
O&M	Operations and Maintenance
OCRB	Original Cost Rate Base
PBI	Performance-Based Incentives paid to retail customers with solar installations based on metered renewable energy production over periods of 9 to 20 years
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
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
PSD	Prevention of Significant Deterioration
REC	Renewable Energy Credit
RES	Renewable Energy Standard
Retail Margin Revenues	A non-GAAP financial measure that demonstrates the underlying revenue trend and performance of our core utility businesses
Regional Haze Rules	Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
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
Rules	Retail Electric Competition Rules established by the ACC in 1999
San Juan	San Juan Generating Station
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SJCC	San Juan Coal Company
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
Springerville	Springerville Generating Station
Springerville Common Facilities	Facilities at Springerville used in common by all four Springerville units

vi

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
Sulfur Credits	Credits applied to the fuel invoice by the supplier when the sulfur content of delivered coal exceeds contractual levels
Sundt	H. Wilson Sundt Generating Station
Sundt Unit 4	Unit 4 of the H. Wilson Sundt Generating Station
TCA	Transmission Cost Adjustor
Tenth Circuit	United States Court of Appeals
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
TEP Credit Agreement	Second Amended and Restated Credit Agreement between TEP and a syndicate of banks, dated as of November 9, 2010 (as amended)
TEP Revolving Credit  Facility	Revolving credit facility under the TEP Credit Agreement
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 Gas and UNS Electric
UNS Credit Agreement	Second Amended and Restated Credit Agreement between UNS Energy Corporation and a syndicate of banks, dated as of November 9, 2010 (as amended)
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES
UNS Energy	UNS Energy Corporation (formally known as UniSource Energy Corporation)
UNS Gas	UNS Gas, Inc., a wholly-owned subsidiary of UES
UNS Gas/UNS Electric Revolver	Revolving credit facility under the Second Amended and Restated Credit Agreement among UNS Gas and UNS Electric as borrowers, UES as guarantor, and a syndicate of banks, dated as of November 9, 2010 (as amended)

vii

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

UNS Energy Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of UNS Energy Corporation and its subsidiaries (the “Company”) as of June 30, 2013, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month and six-month periods ended June 30, 2013 and 2012, the condensed consolidated statement of changes in stockholders’ equity for the six-month period ended June 30, 2013 and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization as of December 31, 2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholders’ equity for the year then ended (not presented herein), and in our report dated February 26, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information and consolidated statement of changes in stockholders' equity information as of December 31, 2012, is fairly stated in all material respects in relation to the consolidated balance sheet and consolidated statement of changes in stockholders' equity from which it has been derived.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

July 30, 2013

1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of

Tucson Electric Power Company:

We have reviewed the accompanying condensed consolidated balance sheet of Tucson Electric Power Company and its subsidiaries (the “Company”) as of June 30, 2013, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month and six-month periods ended June 30, 2013 and 2012, the condensed consolidated statement of changes in stockholder’s equity for the six-month period ended June 30, 2013 and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization as of December 31, 2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholder's equity for the year then ended (not presented herein), and in our report dated February 26, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information and consolidated statement of changes in stockholder's equity information as of December 31, 2012, is fairly stated in all material respects in relation to the consolidated balance sheet and consolidated statement of changes in stockholder's equity from which it has been derived.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

July 30, 2013

2

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,
2013			2012				2013			2012
(Unaudited)							(Unaudited)
Thousands of Dollars							Thousands of Dollars
(Except Per Share Amounts)							(Except Per Share Amounts)
						Operating Revenues
$	285,419		$	292,071		Electric Retail Sales	$	506,279		$	497,502
30,654			25,511			Electric Wholesale Sales	65,052			59,127
20,013			20,006			Gas Retail Sales	71,002			70,215
29,131			26,410			Other Revenues	55,025			52,540
365,217			363,998			Total Operating Revenues	697,358			679,384
						Operating Expenses
86,459			82,325			Fuel	168,148			153,060
57,796			48,203			Purchased Energy	121,955			107,993
4,521			3,412			Transmission	7,707			6,238
2,074			14,215			Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(3,294		)	11,654
150,850			148,155			Total Fuel and Purchased Energy	294,516			278,945
95,143			90,926			Operations and Maintenance	185,043			185,241
36,671			35,190			Depreciation	72,970			70,174
8,119			9,112			Amortization	16,408			17,776
13,631			12,556			Taxes Other Than Income Taxes	27,723			24,794
304,414			295,939			Total Operating Expenses	596,660			576,930
60,803			68,059			Operating Income	100,698			102,454
						Other Income (Deductions)
19			383			Interest Income	28			641
1,734			1,333			Other Income	3,502			3,038
(807		)	(484		)	Other Expense	(1,380		)	(937		)
94			(344		)	Appreciation (Depreciation) in Fair Value of Investments	1,133			1,041
1,040			888			Total Other Income (Deductions)	3,283			3,783
						Interest Expense
17,700			17,602			Long-Term Debt	35,954			36,737
6,249			8,301			Capital Leases	12,498			16,598
346			315			Other Interest Expense	(47		)	1,020
(745		)	(655		)	Interest Capitalized	(1,420		)	(1,186		)
23,550			25,563			Total Interest Expense	46,985			53,169
38,293			43,384			Income Before Income Taxes	56,996			53,068
3,675			17,111			Income Tax Expense	11,033			20,319
$	34,618		$	26,273		Net Income	$	45,963		$	32,749
						Weighted-Average Shares of Common Stock Outstanding (000)
41,598			40,471			Basic	41,569			39,251
41,921			41,630			Diluted	41,898			41,646
						Earnings Per Share
$	0.83		$	0.65		Basic	$	1.11		$	0.83
$	0.83		$	0.64		Diluted	$	1.10		$	0.81
$	0.435		$	0.43		Dividends Declared Per Share	$	0.87		$	0.86

See Notes to Condensed Consolidated Financial Statements.

3

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended					Six Months Ended
June 30,					June 30,
2013		2012			2013		2012
(Unaudited)					(Unaudited)
Thousands of Dollars					Thousands of Dollars
				Comprehensive Income
$	34,618	$	26,273	Net Income	$	45,963	$	32,749
				Other Comprehensive Income
				Net Changes in Fair Value of Cash Flow Hedges:
933		280		net of $(610) and $(184) income taxes
				net of $(1,009) and $(177) income taxes	1,544		272
				Supplemental Executive Retirement Plan (SERP) Benefit Amortization:
68		55		net of $(43) and $(34) income taxes
				net of $(85) and $(15) income taxes	137		163
1,001		335		Total Other Comprehensive Income, Net of Income Taxes	1,681		435
$	35,619	$	26,608	Total Comprehensive Income	$	47,644	$	33,184

See Notes to Condensed Consolidated Financial Statements.

4

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	519,154		$	510,264
Cash Receipts from Gas Retail Sales	91,207			95,063
Cash Receipts from Electric Wholesale Sales	82,273			75,153
Cash Receipts from Operating Springerville Units 3 & 4	49,974			47,720
Cash Receipts from Gas Wholesale Sales	3,494			438
Interest Received	516			2,277
Other Cash Receipts	16,914			13,117
Fuel Costs Paid	(140,185		)	(146,203		)
Purchased Energy Costs Paid	(135,775		)	(126,059		)
Payment of Operations and Maintenance Costs	(121,272		)	(137,634		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(90,554		)	(89,972		)
Wages Paid, Net of Amounts Capitalized	(68,004		)	(66,680		)
Interest Paid, Net of Amounts Capitalized	(34,662		)	(37,986		)
Capital Lease Interest Paid	(18,630		)	(23,177		)
Other Cash Payments	(6,798		)	(3,777		)
Net Cash Flows—Operating Activities	147,652			112,544
Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt	9,104			19,278
Proceeds from Note Receivable	—			5,000
Insurance Proceeds for Replacement Assets	—			2,875
Other Cash Receipts	9,482			10,540
Capital Expenditures	(155,685		)	(166,204		)
Other Cash Payments	(13,095		)	(5,235		)
Net Cash Flows—Investing Activities	(150,194		)	(133,746		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	114,000			324,000
Other Cash Receipts	4,314			2,277
Payments of Capital Lease Obligations	(84,206		)	(76,236		)
Repayments of Borrowings Under Revolving Credit Facilities	(48,000		)	(159,000		)
Common Stock Dividends Paid	(36,079		)	(34,066		)
Payment of Debt Issue/Retirement Costs	(982		)	(1,948		)
Repayments of Long-Term Debt	—			(9,341		)
Other Cash Payments	(730		)	(606		)
Net Cash Flows—Financing Activities	(51,683		)	45,080
Net Increase (Decrease) in Cash and Cash Equivalents	(54,225		)	23,878
Cash and Cash Equivalents, Beginning of Year	123,918			76,390
Cash and Cash Equivalents, End of Period	$	69,693		$	100,268

See Note 10 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

5

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	5,080,381		$	5,005,768
Utility Plant Under Capital Leases	582,669			582,669
Construction Work in Progress	170,436			128,621
Total Utility Plant	5,833,486			5,717,058
Less Accumulated Depreciation and Amortization	(1,961,489		)	(1,921,733		)
Less Accumulated Amortization of Capital Lease Assets	(504,607		)	(494,962		)
Total Utility Plant—Net	3,367,390			3,300,363
Investments and Other Property
Investments in Lease Equity	36,266			36,339
Other	32,736			36,537
Total Investments and Other Property	69,002			72,876
Current Assets
Cash and Cash Equivalents	69,693			123,918
Accounts Receivable—Customer	109,022			93,742
Unbilled Accounts Receivable	63,285			53,568
Allowance for Doubtful Accounts	(6,861		)	(6,545		)
Materials and Supplies	107,795			93,322
Fuel Inventory	52,166			62,019
Deferred Income Taxes—Current	41,263			34,260
Regulatory Assets—Current	54,782			51,619
Investments in Lease Debt	—			9,118
Derivative Instruments	2,961			3,165
Other	15,526			33,567
Total Current Assets	509,632			551,753
Regulatory and Other Assets
Regulatory Assets—Noncurrent	204,034			191,077
Other Assets	26,322			24,360
Total Regulatory and Other Assets	230,356			215,437
Total Assets	$	4,176,380		$	4,140,429

See Notes to Condensed Consolidated Financial Statements.

(Continued)

6

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,078,420	$	1,065,465
Capital Lease Obligations	176,144		262,138
Long-Term Debt	1,522,504		1,498,442
Total Capitalization	2,777,068		2,826,045
Current Liabilities
Current Obligations Under Capital Leases	100,380		90,583
Borrowings Under Revolving Credit Facilities	42,000		—
Accounts Payable—Trade	98,591		107,740
Accrued Taxes Other than Income Taxes	42,429		41,939
Accrued Employee Expenses	21,573		24,094
Interest Accrued	17,055		31,950
Regulatory Liabilities—Current	54,030		43,516
Customer Deposits	35,479		34,048
Derivative Instruments	13,929		14,742
Other	15,776		10,517
Total Current Liabilities	441,242		399,129
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	415,334		364,756
Regulatory Liabilities—Noncurrent	294,950		279,111
Pension and Other Retiree Benefits	157,276		159,401
Derivative Instruments	9,277		12,709
Other	81,233		99,278
Total Deferred Credits and Other Liabilities	958,070		915,255
Commitments, Contingencies, and Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	4,176,380	$	4,140,429

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

7

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Shares Outstanding*	Common Stock		Accumulated Earnings			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Thousands of Shares	(Unaudited) Thousands of Dollars
Balances at December 31, 2012	41,344	$	882,138	$	193,117		$	(9,790	)	$	1,065,465
Comprehensive Income
2013 Year-to-Date Net Income				45,963						45,963
Other Comprehensive Income, net of $(1,094) income taxes							1,681			1,681
Total Comprehensive Income										47,644
Dividends, Including Non-Cash Dividend Equivalents				(36,380		)				(36,380		)
Shares Issued Under Dividend Reinvestment Plan	4	191								191
Shares Issued for Stock Options	36	1,170								1,170
Shares Issued Under Performance Share Awards	57	—								—
Other		330								330
Balances at June 30, 2013	41,441	$	883,829	$	202,700		$	(8,109	)	$	1,078,420

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

See Notes to Condensed Consolidated Financial Statements.

8

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Three Months Ended							Six Months Ended
June 30,							June 30,
2013			2012				2013			2012
(Unaudited)							(Unaudited)
Thousands of Dollars							Thousands of Dollars
						Operating Revenues
$	243,635		$	247,770		Electric Retail Sales	$	428,515		$	414,101
29,542			22,274			Electric Wholesale Sales	63,940			52,040
31,086			29,375			Other Revenues	59,559			57,256
304,263			299,419			Total Operating Revenues	552,014			523,397
						Operating Expenses
84,553			79,554			Fuel	165,351			149,528
28,410			20,862			Purchased Power	47,338			34,488
1,730			1,401			Transmission	2,595			2,363
5,274			12,811			Increase to Reflect PPFAC Recovery Treatment	2,914			5,125
119,967			114,628			Total Fuel and Purchased Energy	218,198			191,504
82,011			78,683			Operations and Maintenance	159,835			161,149
28,861			27,545			Depreciation	57,418			55,012
9,052			10,028			Amortization	18,275			19,620
10,939			10,324			Taxes Other Than Income Taxes	22,108			20,009
250,830			241,208			Total Operating Expenses	475,834			447,294
53,433			58,211			Operating Income	76,180			76,103
						Other Income (Deductions)
12			43			Interest Income	8			69
1,270			1,209			Other Income	2,438			2,286
(2,472		)	(1,640		)	Other Expense	(4,717		)	(3,128		)
94			(344		)	Appreciation (Depreciation) in Fair Value of Investments	1,133			1,041
(1,096		)	(732		)	Total Other Income (Deductions)	(1,138		)	268
						Interest Expense
13,991			13,378			Long-Term Debt	28,564			27,294
6,249			8,301			Capital Leases	12,498			16,598
192			246			Other Interest Expense	(168		)	777
(534		)	(598		)	Interest Capitalized	(1,027		)	(1,020		)
19,898			21,327			Total Interest Expense	39,867			43,649
32,439			36,152			Income Before Income Taxes	35,175			32,722
1,652			14,242			Income Tax Expense	2,909			12,273
$	30,787		$	21,910		Net Income	$	32,266		$	20,449

See Notes to Condensed Consolidated Financial Statements.

9

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended					Six Months Ended
June 30,					June 30,
2013		2012			2013		2012
(Unaudited)					(Unaudited)
Thousands of Dollars					Thousands of Dollars
				Comprehensive Income
$	30,787	$	21,910	Net Income	$	32,266	$	20,449
				Other Comprehensive Income
				Net Changes in Fair Value of Cash Flow Hedges:
878		389		net of $(574) and $(255) income taxes
				net of $(952) and $(279) income taxes	1,456		427
				SERP Benefit Amortization:
68		55		net of $(43) and $(34) income taxes
				net of $(85) and $(15) income taxes	137		163
946		444		Total Other Comprehensive Income, Net of Income Taxes	1,593		590
$	31,733	$	22,354	Total Comprehensive Income	$	33,859	$	21,039

See Notes to Condensed Consolidated Financial Statements.

10

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	435,779		$	420,296
Cash Receipts from Electric Wholesale Sales	75,803			62,884
Cash Receipts from Operating Springerville Units 3 & 4	49,974			47,720
Reimbursement of Affiliate Charges	12,695			11,437
Cash Receipts from Gas Wholesale Sales	3,145			26
Interest Received	509			1,523
Other Cash Receipts	13,320			9,815
Fuel Costs Paid	(139,596		)	(144,929		)
Payment of Operations and Maintenance Costs	(117,133		)	(133,845		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(68,574		)	(67,013		)
Wages Paid, Net of Amounts Capitalized	(57,483		)	(55,185		)
Purchased Power Costs Paid	(40,949		)	(30,437		)
Interest Paid, Net of Amounts Capitalized	(27,590		)	(27,966		)
Capital Lease Interest Paid	(18,630		)	(23,177		)
Income Taxes Paid	—			(1,796		)
Other Cash Payments	(5,728		)	(2,847		)
Net Cash Flows—Operating Activities	115,542			66,506
Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt	9,104			19,278
Insurance Proceeds for Replacement Assets	—			2,875
Other Cash Receipts	7,920			7,111
Capital Expenditures	(118,210		)	(142,385		)
Purchase of Intangibles—Renewable Energy Credits	(11,390		)	(4,207		)
Net Cash Flows—Investing Activities	(112,576		)	(117,328		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	78,000			184,000
Other Cash Receipts	1,130			1,087
Payments of Capital Lease Obligations	(84,206		)	(76,236		)
Repayments of Borrowings Under Revolving Credit Facility	(48,000		)	(45,000		)
Payment of Debt Issue/Retirement Costs	(982		)	(1,948		)
Repayments of Long-Term Debt	—			(6,535		)
Other Cash Payments	(534		)	(440		)
Net Cash Flows—Financing Activities	(54,592		)	54,928
Net Increase (Decrease) in Cash and Cash Equivalents	(51,626		)	4,106
Cash and Cash Equivalents, Beginning of Year	79,743			27,718
Cash and Cash Equivalents, End of Period	$	28,117		$	31,824

See Note 10 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

11

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	4,407,267		$	4,348,041
Utility Plant Under Capital Leases	582,669			582,669
Construction Work in Progress	123,693			98,460
Total Utility Plant	5,113,629			5,029,170
Less Accumulated Depreciation and Amortization	(1,812,994		)	(1,783,787		)
Less Accumulated Amortization of Capital Lease Assets	(504,607		)	(494,962		)
Total Utility Plant—Net	2,796,028			2,750,421
Investments and Other Property
Investments in Lease Equity	36,266			36,339
Other	31,295			35,091
Total Investments and Other Property	67,561			71,430
Current Assets
Cash and Cash Equivalents	28,117			79,743
Accounts Receivable—Customer	89,172			71,813
Unbilled Accounts Receivable	52,420			33,782
Allowance for Doubtful Accounts	(4,913		)	(4,598		)
Accounts Receivable—Due from Affiliates	3,018			5,720
Materials and Supplies	94,717			80,377
Fuel Inventory	51,871			61,737
Deferred Income Taxes—Current	45,185			37,212
Regulatory Assets—Current	36,283			34,345
Investments in Lease Debt	—			9,118
Other	15,571			34,393
Total Current Assets	411,441			443,642
Regulatory and Other Assets
Regulatory Assets—Noncurrent	190,488			178,330
Other Assets	19,633			17,223
Total Regulatory and Other Assets	210,121			195,553
Total Assets	$	3,485,151		$	3,461,046

See Notes to Condensed Consolidated Financial Statements.

(Continued)

12

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	894,786	$	860,927
Capital Lease Obligations	176,144		262,138
Long-Term Debt	1,223,505		1,223,442
Total Capitalization	2,294,435		2,346,507
Current Liabilities
Current Obligations Under Capital Leases	100,380		90,583
Borrowings Under Revolving Credit Facility	30,000		—
Accounts Payable—Trade	81,406		82,122
Accounts Payable—Due to Affiliates	2,924		3,134
Accrued Taxes Other than Income Taxes	35,355		33,060
Accrued Employee Expenses	18,161		20,715
Interest Accrued	12,069		26,965
Regulatory Liabilities—Current	29,562		20,822
Customer Deposits	26,174		24,846
Derivative Instruments	6,959		4,899
Other	11,247		7,085
Total Current Liabilities	354,237		314,231
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	357,202		319,216
Regulatory Liabilities—Noncurrent	256,292		241,189
Pension and Other Retiree Benefits	147,152		149,718
Derivative Instruments	7,197		10,565
Other	68,636		79,620
Total Deferred Credits and Other Liabilities	836,479		800,308
Commitments, Contingencies, and Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	3,485,151	$	3,461,046

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

13

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY

	Common Stock		Capital Stock Expense			Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	(Unaudited) Thousands of Dollars
Balances at December 31, 2012	$	888,971	$	(6,357	)	$	(12,157	)	$	(9,530	)	$	860,927
Comprehensive Income
2013 Year-to-Date Net Income						32,266						32,266
Other Comprehensive Income, net of $(1,037) income taxes									1,593			1,593
Total Comprehensive Income												33,859
Balances at June 30, 2013	$	888,971	$	(6,357	)	$	20,109		$	(7,937	)	$	894,786

See Notes to Condensed Consolidated Financial Statements.

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Unaudited

NOTE 1. FINANCIAL STATEMENT PRESENTATION

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

We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2012 Annual Report on Form 10-K.

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

REVISION OF PRIOR PERIOD UNS ENERGY INCOME STATEMENT

During the first three quarters of 2012, we incorrectly reported UNS Electric's sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $3 million for the three months ended and $7 million for the six months endedJune 30, 2012. This error had no impact on operating income, net income, retained earnings, or cash flows.

We assessed the impact of this error on prior period financial statements and concluded it was not material to any period. However, this error was significant to individual income statement line items. As a result, in accordance with GAAP, we revised our prior period income statement as follows:

	UNS Energy
	Three Months Ended				Six Months Ended
	June 30, 2012				June 30, 2012
	As Reported		As Revised		As Reported		As Revised
	Thousands of Dollars				Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	28,684	$	25,511	$	65,787	$	59,127
Purchased Energy	51,376		48,203		114,653		107,993
Total Fuel and Purchased Energy	151,328		148,155		285,605		278,945
Total Operating Expenses	299,112		295,939		583,590		576,930

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2013, we adopted authoritative guidance that:

• Requires additional disclosures for amounts reclassified out of accumulated other comprehensive income by component. See Note 12.

• Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 11.

• Allows an additional option for impairment testing of indefinite-lived intangible assets. We had no impairment indicator as our only indefinite-lived intangible assets, Renewable Energy Credits (RECs), are currently recoverable under the Renewable Energy Standard (RES) as we use the RECs to comply with the standard’s renewable resources requirements.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 2. REGULATORY MATTERS

RATES AND REGULATION

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

2013 TEP RATE ORDER

In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

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

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

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

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

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

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

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

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

The 2013 TEP Rate Order also includes:

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

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

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

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

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

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

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

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

PENDING UNS ELECTRIC RATE CASE

In December 2012, as required in the 2010 UNS Electric Rate Order, UNS Electric filed with the ACC a general rate case, on a cost-of-service basis, requesting the following:

• a non-fuel Base Rate increase of $7.5 million, or 4.6%;

• an OCRB of approximately $217 million and a FVRB of $286 million;

• a return on equity of 10.5%, a long-term cost of debt of 5.97%;

• a capital structure of approximately 53% equity and 47% long-term debt; and

• a 1.6% return on the fair value increment of rate base. The fair value increment of rate base represents the difference between OCRB and FVRB of approximately $69 million.

UNS Electric also requested the following:

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

• a Transmission Cost Adjustor (TCA). The TCA would allow UNS Electric to recover, on a more timely basis, transmission costs associated with serving retail customers.

ACC Staff and other parties have filed testimony with recommendations ranging from no rate increase to a 0.8% rate increase.

REGULATORY ASSETS AND LIABILITIES

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

	June 30, 2013						December 31, 2012
	UNS Energy			TEP			UNS Energy			TEP
	Millions of Dollars
Regulatory Assets – Current	$	55		$	36		$	52		$	34
Regulatory Assets – Noncurrent (1)	204			190			191			178
Regulatory Liabilities—Current (2)	(54		)	(30		)	(44		)	(21		)
Regulatory Liabilities – Noncurrent (3)	(295		)	(256		)	(279		)	(241		)
Total Net Regulatory Assets (Liabilities)	$	(90	)	$	(60	)	$	(80	)	$	(50	)

⁽¹⁾  Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment, See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.

⁽²⁾  Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.

⁽³⁾  Regulatory Liabilities - Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF REGULATORY ACCOUNTING

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

• Reflecting regulatory pension assets as part of Accumulated Other Comprehensive Income (AOCI)

• Writing off the remaining regulatory assets as an expense and regulatory liabilities as income in the income statements

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

• TEP would have recorded an extraordinary after-tax gain of $112 million and an after-tax loss in AOCI of $76 million;

• UNS Gas would have recorded an extraordinary after-tax gain of $24 million and an after-tax loss in AOCI of $2 million; and

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

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

NOTE 3. BUSINESS SEGMENTS

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

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

(2) UNS Gas, a regulated gas distribution utility

(3) UNS Electric, a regulated electric utility

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

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Three Months Ended June 30, 2013
Operating Revenues – External	$	300	$	21	$	44	$	—	$	—		$	365
Operating Revenues – Intersegment(1)	4		1		—		4		(9		)	—
Net Income	31		—		4		—		—			35
Three Months Ended June 30, 2012
Operating Revenues – External	$	295	$	21	$	48	$	—	$	—		$	364
Operating Revenues – Intersegment(1)	4		1		—		5		(10		)	—
Net Income	22		—		4		—		—			26

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Six Months Ended June 30, 2013
Operating Revenues – External	$	543	$	73	$	80	$	1	$	—		$	697
Operating Revenues – Intersegment(1)	9		1		1		8		(19		)	—
Net Income	32		8		6		—		—			46
Six Months Ended June 30, 2012
Operating Revenues – External	$	515	$	73	$	91	$	—	$	—		$	679
Operating Revenues – Intersegment(1)	8		2		1		9		(20		)	—
Net Income	20		5		7		1		—			33

⁽¹⁾  Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

NOTE 4. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

In addition to those reported in our 2012 Annual Report on Form 10-K, we entered into the following new long-term commitments.

TEP COMMITMENTS

Purchase Power Contracts

TEP entered into new forward purchase power commitments that will settle through December 2014. Some of these contracts are at fixed prices per MWh and others are indexed to natural gas prices. Based on projected market prices as of June 30, 2013, TEP's estimated minimum payment obligations for these purchases are $9 million in 2014.

TEP has a 20-year Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $4 million per year in each of the next five years and approximately $56 million total thereafter.

RES Recoverable Incentives

In exchange for the environmental attributes, or RECs, TEP and UNS Electric make two types of incentive payments to customers who install distributed generation: up-front incentive payments and Performance-Based Incentives (PBIs). Both up-front incentive and PBI payments are recovered through the RES tariff. Up-front incentive payments are distinguished by the following:

• residential and small commercial customers;

• small installations; and

• up-front payment upon installation.

PBIs are distinguished by the following:

• large commercial customers;

• large installations; and

• based on metered renewable energy production over periods ranging from 9 to 20 years.

In the second quarter 2013, TEP's total obligation related to RES PBI payments over future periods increased by $4 million from $62 million on December 31, 2012, to $66 million on June 30, 2013.

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

UNS GAS COMMITMENTS

UNS Gas entered into new forward energy commitments that settle through May 2016 at fixed prices per million British thermal units (MMBtu). UNS Gas’ minimum payment obligations for these purchases are $3 million in 2014, $2 million in 2015, and $1 million in 2016.

UNS ELECTRIC COMMITMENTS

Purchase Power Contracts

UNS Electric entered into new forward purchase power commitments that will settle through September 2015 at fixed prices per MWh. UNS Electric’s minimum payment obligations for these purchases are $4 million in 2014 and $3 million in 2015.

RES Performance-Based Incentives

UNS Electric is contractually obligated to retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In 2013, UNS Electric's total obligation for RES PBIs increased by approximately $1 million, from $6 million on December 31, 2012, to $7 million on June 30, 2013. UNS Electric will make payments over periods ranging from 10 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff.

TEP CONTINGENCIES

Claim Related to San Juan Generating Station

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

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 matter is stayed until August 1, 2013 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.

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 Generating Station (Navajo), San Juan, and Four Corners. TEP’s share of reclamation costs is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) recorded was $17 million at June 30, 2013 and $16 million at December 31, 2012.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

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

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

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric expect to abandon the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. See Note 2. In 2012, TEP recorded a regulatory asset of $5 million and UNS Electric recorded a regulatory asset of $0.2 million for the balance deemed probable of recovery.

Springerville Unit 1 Leases

The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030. TEP has a fair market value purchase option for facilities under the Springerville Unit 1 Leases, which requires TEP to issue notification of intent to purchase by August 31, 2013. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal process to determine the fair market value purchase price, in accordance with the Springerville Unit 1 Leases. Based on that appraisal, TEP has the option to pay $159 million in 2015 for the 86% interest not already owned by TEP. In 2012, TEP initiated a proceeding seeking judicial confirmation of the results of the appraisal process in Federal District Court. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for the leased interest. In January 2013, the Federal District Court denied TEP's petition on the grounds that the court lacks jurisdiction in the matter. In February 2013, TEP appealed the matter to the U.S. Court of Appeals for the Ninth Circuit, where it is currently pending. TEP cannot predict the outcome of this matter.

Resolution of Contingencies

Springerville Generating Station Unit 3 Outage

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

ENVIRONMENTAL MATTERS

Environmental Regulation

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

Hazardous Air Pollutant Requirements

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

Navajo

Based on the EPA’s final standards, Navajo may require mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. 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.

San Juan

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

Four Corners

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

Springerville Generating Station

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

Sundt Generating Station

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

Regional Haze Rules

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

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

Navajo

In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, reached an agreement that would achieve greater NOx emission reductions than the EPA's proposed BART rule. The stakeholder group has submitted the agreement for the EPA's consideration 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 required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.

San Juan

In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

installation of SCR technology with sorbent injection on all four units to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.

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

In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement that outlines an alternative to the FIP. The terms of the agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of Selective Non-Catalytic Reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW or 50%, of San Juan Units 1 and 2. At June 30, 2013, the book value of TEP's share of San Juan Units 1 and 2 was $214 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. TEP cannot predict the ultimate outcome of this matter.

Four Corners

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

Springerville

Provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018.

Sundt

In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule. Under the Regional Haze Rule, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART determination. The EPA postponed its expected release of a proposed BART requirement for Sundt Unit 4 until September 2013, with a final determination expected in February 2014.

Greenhouse Gas Regulation

On June 25, 2013, President Obama directed the EPA to move forward with regulations to limit carbon emissions from new and existing fossil fueled power plants.  Specifically, the President directed the EPA to issue a re-proposed rule for new power plants by September 20, 2013. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

Additionally, the President ordered the EPA to:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

• propose carbon emission standards for existing power plants by June 1, 2014;

• finalize those standards by June 1, 2015; and

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

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

NOTE 5. DEBT AND CREDIT FACILITIES

We summarize below the significant changes to our debt from those reported in our 2012 Annual Report on Form 10-K.

TEP TAX-EXEMPT BONDS ISSUED

In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 1, 2023. The proceeds from the sale of the bonds, together with $0.5 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received nor disbursed by TEP. TEP capitalized approximately $1 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statement through September 2029, the term of the bonds.

UNS ENERGY'S AND TEP'S CREDIT RATING UPGRADES

In June 2013, as a result of an upgrade in the senior secured rating of UNS Energy and a senior unsecured rating of TEP, the following agreements, with pricing tied to credit ratings for short-term borrowings, changed:

• Under the UNS Credit Agreement, the interest rate decreased from London Interbank Offered Rate (LIBOR) plus 1.75% to LIBOR plus 1.5%;

• Under the TEP Credit Agreement, the interest rate decreased from LIBOR plus 1.125% to LIBOR plus 1.0% ; and the margin rate on the $186 million letter of credit facility decreased from 1.125% to 1.0% ; and

• Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit decreased from 1.5% to 1.25% per annum.

COVENANT COMPLIANCE

At June 30, 2013, we were in compliance with the terms of our credit agreements, UNS Electric's term loan, and TEP's reimbursement agreement.

NOTE 6. 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,
	2013			2012		2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	14		$	15	$	12		$	13
State Income Tax Expense, Net of Federal Deduction	2			2		2			1
Investment Tax Credit Basis Difference	(11		)	—		(11		)	—
Other	(1		)	—		(1		)	—
Total Federal and State Income Tax Expense	$	4		$	17	$	2		$	14

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

	UNS Energy						TEP
	Six Months Ended June 30,
	2013			2012			2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	20		$	19		$	12		$	11
State Income Tax Expense, Net of Federal Deduction	3			2			2			2
Cash Surrender Value of Life Insurance	—			(1		)	—			(1		)
Investment Tax Credit Basis Difference	(11		)	—			(11		)	—
Other	(1		)	—			—			—
Total Federal and State Income Tax Expense	$	11		$	20		$	3		$	12

Investment Tax Credit Basis Difference Adjustment

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

Uncertain Tax Positions

We recognize tax benefits from uncertain tax positions if it is more likely than not that the tax position will be sustained on examination by the taxing authorities. Each uncertain tax position is recognized up to the amount most likely to be sustained on examination and adjusted with changes in facts and circumstances. A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	UNS Energy			TEP
	Millions of Dollars
Unrecognized Tax Benefits at December 31, 2012	$	30		$	23
Additions Based on Tax Positions Taken in the Current Year	1			1
Reduction of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(22		)
Unrecognized Tax Benefits at June 30, 2013	$	3		$	2

In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources.  These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation.  As a result of the IRS ruling in the first quarter of 2013, UNS Energy reduced unrecognized tax benefits by $28 million, and TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.

The IRS completed its audit of the 2009 and 2010 tax returns in March 2013 resulting in no change to the financial statements.

In April 2013, the IRS provided notice of intent to audit the 2011 tax returns.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 7. 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,
	2013			2012			2013		2012
	Millions of Dollars
Service Cost	$	3		$	2		$	1	$	1
Interest Cost	4			4			1		1
Expected Return on Plan Assets	(5		)	(4		)	—		—
Actuarial Loss Amortization	2			2			—		—
Net Periodic Benefit Cost	$	4		$	4		$	2	$	2

	Pension Benefits						Other Retiree Benefits
	Six Months Ended June 30,
	2013			2012			2013		2012
	Millions of Dollars
Service Cost	$	6		$	5		$	2	$	1
Interest Cost	8			8			1		2
Expected Return on Plan Assets	(10		)	(9		)	—		—
Actuarial Loss Amortization	4			4			—		—
Net Periodic Benefit Cost	$	8		$	8		$	3	$	3

NOTE 8. SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS

In May 2013, the UNS Energy Compensation Committee granted 8,870 restricted stock units to non-employee directors at a grant date fair value of $48.99 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. The grant date fair value was calculated by reducing the grant date share price by the present value of the dividends expected to be paid on the shares during the vesting period. Fully vested but undistributed non-employee director stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. We issue UNS Energy Common Stock (Common Stock) for the vested stock units in the January following the year the person is no longer a director.

In February 2013, the UNS Energy Compensation Committee granted 21,560 restricted stock units to certain management employees at a grant date fair value, based on the grant date share price, of $46.23 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. These restricted stock units accrue dividend equivalents, during the vesting period, which are distributed in shares of Common Stock upon vesting.

PERFOMANCE SHARES

In February 2013, the UNS Energy Compensation Committee granted 43,120 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $45.54 per share. Those awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Return to the companies included in the Edison Electric Institute Index during the performance period of January 1, 2013 through December 31, 2015. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date share price, of $46.23 per share and will be paid out in Common Stock based on cumulative

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

net income for the three-year period ended December 31, 2015. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents, during the performance period, which are paid upon vesting.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded less than $1 million of share-based compensation expense for the three months ended June 30, 2013 and June 30, 2012. For the six months ended June 30, 2013 and June 30, 2012, UNS Energy and TEP recorded share-based compensation expense of $1 million .

At June 30, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At June 30, 2013, 1 million shares were awarded but not yet issued, including target performance based shares, under the share-based compensation plans.

NOTE 9. UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options, share-based compensation awards, or UNS Energy's Convertible Senior Notes were exercised or converted into Common Stock. We excluded anti-dilutive stock options from the calculation of diluted EPS. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the remaining notes, not yet converted, were converted to Common Stock.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Thousands of Dollars
Numerator:
Net Income	$	34,618	$	26,273	$	45,963	$	32,749
Income from Assumed Conversion of Convertible Senior Notes (1)	—		237		—		1,100
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	34,618	$	26,510	$	45,963	$	33,849
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,427		40,322		41,404		39,107
Fully Vested Deferred Stock Units	171		149		165		144
Total Weighted Average Common Stock Outstanding – Basic	41,598		40,471		41,569		39,251
Effect of Dilutive Securities:
Convertible Senior Notes (1)	—		909		—		2,125
Options and Stock Issuable Under Share-Based Compensation Plans	323		250		329		270
Total Weighted Average Common Stock Outstanding – Diluted	41,921		41,630		41,898		41,646

⁽¹⁾ In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

We excluded the following outstanding stock options, with an exercise price above market, from our diluted EPS computation as their effect would be anti-dilutive:

	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
	Thousands of Shares
Stock Options	—	101	—	101

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

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

	UNS Energy
	Six Months Ended June 30,
	2013			2012
	Thousands of Dollars
Net Income	$	45,963		$	32,749
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	72,970			70,174
Amortization Expense	16,408			17,776
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	3,516			3,234
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,515			1,545
Provision for Retail Customer Bad Debts	936			1,571
Use of RECs for Compliance	8,106			3,055
Deferred Income Taxes	36,644			17,397
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—
Pension and Retiree Expense	11,391			10,927
Pension and Retiree Funding	(8,924		)	(10,957		)
Share-Based Compensation Expense	1,390			1,170
Allowance for Equity Funds Used During Construction	(2,463		)	(1,920		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(3,294		)	11,654
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(20,706		)	(19,547		)
Materials and Fuel Inventory	8,777			(21,597		)
Accounts Payable	(9,576		)	(2,594		)
Income Taxes	(15,980		)	2,062
Interest Accrued	(6,885		)	(7,839		)
Taxes Other Than Income Taxes	490			952
Other	15,413			2,732
Net Cash Flows – Operating Activities	$	147,652		$	112,544

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

	TEP
	Six Months Ended June 30,
	2013			2012
	Thousands of Dollars
Net Income	$	32,266		$	20,449
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	57,418			55,012
Amortization Expense	18,275			19,620
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	2,987			2,506
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,216			1,072
Provision for Retail Customer Bad Debts	711			1,104
Use of RECs for Compliance	7,414			2,622
Deferred Income Taxes	24,883			10,810
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—
Pension and Retiree Expense	9,939			9,644
Pension and Retiree Funding	(8,493		)	(9,856		)
Share-Based Compensation Expense	1,108			923
Allowance for Equity Funds Used During Construction	(1,763		)	(1,646		)
Increase (Decrease) to Reflect PPFAC Recovery	2,914			5,125
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(30,452		)	(34,287		)
Materials and Fuel Inventory	8,923			(21,189		)
Accounts Payable	(11		)	7,686
Income Taxes	(10,798		)	1,769
Interest Accrued	(6,886		)	(6,805		)
Taxes Other Than Income Taxes	2,295			3,454
Other	11,347			(1,507		)
Net Cash Flows – Operating Activities	$	115,542		$	66,506

Non-Cash Transactions

In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. See Note 5.

In the first six months of 2012, UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Stock, resulting in non-cash transactions.

In the first six months of 2012, TEP's redemption of $193 million of tax-exempt bonds resulted in non-cash transactions.

NOTE 11. 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. Level 3 inputs are unobservable and supported by little or no market activity.

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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

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

• For Investment in Lease Debt, we calculate the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporate the impact of counterparty credit risk using market credit default swap data.

• 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, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		24		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,523		1,572		1,498		1,583
TEP	Level 2	1,224		1,245		1,223		1,271

TEP's Investment in Lease Debt matured in January 2013. This investment was stated at amortized cost, which means the purchase cost was adjusted for the amortization of the premium and discount to maturity.

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. There were no transfers between Levels 1, 2, or 3 for either reporting period.

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

	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, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	15		$	15	$	—		$	—		$	—		$	15
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	20			—		20			—			—			20
Energy Contracts - Regulatory Recovery(3)	5			—		2			3			(3		)	2
Total Assets	42			17		22			3			(3		)	39
Liabilities
Energy Contracts - Regulatory Recovery(3)	(12		)	—		(6		)	(6		)	3			(9		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(9		)	—		(9		)	—			—			(9		)
Total Liabilities	(23		)	—		(15		)	(8		)	3			(20		)
Net Total Assets (Liabilities)	$	19		$	17	$	7		$	(5	)	$	—		$	19

	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, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery(3)	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	20			—		20			—			—			20
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	25			2		21			2			(1		)	24
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(2		)	(1		)	1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(9		)	—		(9		)	—			—			(9		)
Total Liabilities	(14		)	—		(11		)	(3		)	1			(13		)
Net Total Assets (Liabilities)	$	11		$	2	$	10		$	(1	)	$	—		$	11

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1		$	1	$	—		$	—		$	—		$	1
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	30			8		20			2			(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(3		)	—			1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(15		)	—		(13		)	(2		)	1			(14		)
Net Total Assets (Liabilities)	$	15		$	8	$	7		$	—		$	—		$	15

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

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

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

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

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

32

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

DERIVATIVE INSTRUMENTS

Regulatory Recovery

We are exposed to energy price risk associated with our gas and purchased power requirements. We reduce our energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or Purchased Gas Adjustor (PGA). See Note 2.

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange pricing, adjusted for basis differences, 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 options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, correlations, interest rates, and forward price curves.

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

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

Cash Flow Hedges

We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. These swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. This swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 12. The amount expected to be reclassified to earnings within the next twelve months is estimated to be $4 million.

Financial Impact of Energy Contracts

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

	UNS Energy					TEP
	Three Months Ended June 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	9	$	(17	)	$	3	$	(6	)

	UNS Energy					TEP
	Six Months Ended June 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	—	$	(9	)	$	1	$	(1	)

Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At June 30, 2013, UNS Energy and TEP have energy contracts that will settle through the second quarter of 2016.

33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	June 30, 2013	December 31, 2012	June 30, 2013	December 31, 2012
Power Contracts GWh	2,231	2,228	909	820
Gas Contracts GBtu	20,289	17,851	8,090	7,958

Level 3 Fair Value Measurements

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

		Fair Value at
		June 30, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	2	$	(8	)	Market price per MWh	$	24.00		-	$	53.25
Option Contracts(2)	Option model	1		—			Market Price per MWh	$	34.00		-	$	44.75
							Power Volatility	29.75		%	-	77.2		%
							Market Price per MMbtu	$	3.38		-	$	3.65
							Gas Volatility	29.69		%	-	32.37		%
Level 3 Energy Contracts		$	3	$	(8	)

⁽¹⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

⁽²⁾  All of the option contracts relate to TEP.

Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statement.

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

	Three Months Ended June 30, 2013
	UNS Energy			TEP
	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	)	$	—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

	Six Months Ended June 30, 2013
	UNS Energy		TEP
	Millions of Dollars
Balances at December 31, 2012	(5	)	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(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	)

	Three Months Ended June 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at March 31, 2012	$	(13	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	2			(1		)
Settlements	4			—
Balances at June 30, 2012	$	(7	)	$	(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		$	—

	Six Months Ended June 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)	—
Settlements	7			(1		)
Balances at June 30, 2012	$	(7	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

CREDIT RISK

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. The impact of counterparty credit risk and our own credit risk on the fair value of derivative contracts was less than $0.1 million at June 30, 2013 and at December 31, 2012.

At June 30, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $30 million for UNS Energy and $13 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $30 million for UNS Energy and $13 million for TEP.

35

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 12. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The realized changes in accumulated other comprehensive income by component are as follows:

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Three Months Ended June 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(346	)	$	(293	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(604		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(191		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	451			429
Realized Losses on Cash Flow Hedges, Net of Taxes	(690		)	(659		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(111		)	(111		)	Other Expense
Tax Benefit	43			43
Amortization, Net of Taxes	(68		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(758	)	$	(727	)

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Six Months Ended June 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(676	)	$	(575	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,208		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(191		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	820			781
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,255		)	(1,193		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(222		)	(222		)	Other Expense
Tax Benefit	85			85
Amortization, Net of Taxes	(137		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,392	)	$	(1,330	)

36

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded) - Unaudited

NOTE 13. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT

The Financial Accounting Standards Board issued authoritative guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. Upon implementation entities will continue reporting their obligations under joint and several arrangements. In addition, the entity must measure, recognize, and disclose in the financial statements amounts they expect to pay on behalf of co-obligors for fixed obligations as of the balance sheet date. This guidance will be effective in the first quarter of 2014. We are evaluating the impact to our financial statements and disclosures.

NOTE 14. REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

37

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 2013, compared with the same periods in 2012;

• factors affecting our results and outlook;

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

• dividends; and

• critical accounting estimates.

Management’s Discussion and Analysis should be read in conjunction with (i) UNS Energy’s and TEP's 2012 Annual Report on Form 10-K and (ii) the Condensed Consolidated Financial Statements that begin on page three of this document. The Condensed Consolidated Financial Statements present the results of operations for the three and six months periods ended June 30, 2013 and 2012. Management’s Discussion and Analysis explains the differences between periods for specific line items of the Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

OVERVIEW OF CONSOLIDATED BUSINESS

UNS Energy is a utility services holding company engaged, through its primary 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 and UniSource Energy Services, Inc.

TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of June 30, 2013. TEP generates, transmits, and distributes electricity to approximately 408,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agricultural Improvement and Power District (SRP).

UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 148,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated public utility, which generates, transmits, and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties.

UNS Energy's non-reportable business segments include Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy Development (UED). UED's and Millennium's investments in unregulated businesses represent less than 1% of UNS Energy's assets as of June 30, 2013.

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

OUTLOOK 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:

• Developing strategic responses to the Arizona Corporation Commission's inquiry on opening Arizona to retail electric competition that protect the financial stability of our utility businesses and provide benefits to our customers.

• Developing a long-term diversification strategy for our generating portfolio. We are evaluating several energy resource options including coal, natural gas, and renewable generating resources. 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.

38

• 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.

• 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.

• Expanding TEP's and UNS Electric's portfolio of renewable energy resources and programs to meet Arizona's Renewable Energy Standard (RES) while creating ownership opportunities for renewable energy projects that benefit customers, shareholders, and the communities we serve.

• Developing strategic responses to Arizona's Energy Efficiency Standards that protect the financial stability of our utility businesses and provide benefits to our customers.

RESULTS OF OPERATIONS

Contribution by Business Segment

The table below shows the contributions to our consolidated after-tax earnings by business segment:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Millions of Dollars
TEP	$	31	$	22	$	32	$	20
UNS Gas	—		—		8		5
UNS Electric	4		4		6		7
Other Non-Reportable Segments and Adjustments (1)	—		—		—		1
Consolidated Net Income	$	35	$	26	$	46	$	33

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

Executive Overview

Second Quarter of 2013 Compared with the Second Quarter of 2012

TEP

TEP reported net income of $31 million in the second quarter of 2013 compared with net income of $22 million in the second quarter of 2012. The increase in net income is due in part to: a $1 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; a $1 million decrease in interest expense due in part to a decline in capital lease obligation balances; partially offset by a $1 million decrease in retail margin revenues; and a $1 million increase in Base O&M due in part to unplanned maintenance on TEP's generating facilities.

Additionally, TEP's net income in the second quarter of 2013 includes an income tax benefit of $11 million. 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. See Note 6. TEP's second quarter 2013 results also include additional fuel expense of $3 million related to a one-time credit to customers resulting from the 2013 TEP Rate Order. See Tucson Electric Power Company, Results of Operations, for more information.

UNS Gas

UNS Gas reported no net income or net loss in the second quarters of 2013 and 2012. See UNS Gas, Results of Operations, for more information.

39

UNS Electric

UNS Electric reported net income of $4 million in the second quarters of 2013 and 2012. See UNS Electric, Results of Operations, for more information.

Six Months Ended June 30, 2013 Compared with the Six Months Ended June 30, 2012

TEP

TEP reported net income of $32 million in the first six months of 2013 compared with net income of $20 million in the same period of 2012. The increase in net income is due in part to: a 1.1% increase in retail sales volumes related to cold weather during the first quarter of 2013 that contributed to a $3 million increase in retail margin revenues; and a $2 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; partially offset by a $2 million increase in Base O&M due in part to unplanned maintenance on TEP's generating facilities; a $1 million increase in depreciation and amortization expense related to an increase in net utility plant in service; and a $2 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

Additionally, TEP's net income in the first six months of 2013 includes an income tax benefit of $11 million and additional fuel expense of $3 million related to a one-time credit to customers resulting from the 2013 TEP Rate Order. See Note 6 and Tucson Electric Power Company, Results of Operations, for more information.

UNS Gas

UNS Gas reported net income of $8 million in the first six months of 2013 compared with net income of $5 million in the same period of 2012. The increase in net income is due primarily to: a $2 million increase in retail margin revenues related to cold weather that contributed to a 10.0% increase in retail therm sales; and a non-fuel base rate increase that was effective in May 2012. See UNS Gas, Results of Operations, for more information.

UNS Electric

UNS Electric reported net income of $6 million in the first six months of 2013 compared with net income of $7 million in the same period last year. The decrease in net income was due in part to the loss of an industrial customer in the second half of 2012. See UNS Electric, Results of Operations, for more information.

Operations and Maintenance Expense

The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
UNS Energy Base O&M (Non-GAAP)(1)	$	71	$	68	$	141	$	137
Reimbursed Expenses Related to Springerville Units 3 and 4	16		13		30		27
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs(2)	8		10		14		21
Total UNS Energy O&M (GAAP)	$	95	$	91	$	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 generally accepted accounting principles (GAAP) in the United States of America. 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.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Dividends from UNS Energy’s subsidiaries represent the parent company’s main source of liquidity. Under UNS Energy’s tax sharing agreement, subsidiaries make income tax payments to UNS Energy, which makes payments on behalf of the consolidated group to taxing authorities. See Income Tax Position, below, for more information.

The table below provides a summary of the liquidity position of UNS Energy and each of its segments:

Balances as of July 17, 2013	Cash and  Cash Equivalents		Borrowings under Revolving Credit Facility(1)		Amount Available under Revolving Credit Facility
	Millions of Dollars
UNS Energy Stand-Alone	$	2	$	67	$	58
TEP	32		31		169
UNS Gas(2)	33		—		70
UNS Electric(2)	13		12		58
Other(3)	3		N/A		N/A
Total	$	83

⁽¹⁾  Includes Letters of Credit (LOCs) issued under revolving credit facilities.

⁽²⁾  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.

⁽³⁾  Includes cash and cash equivalents at Millennium and UED.

Dividends from Subsidiaries

UNS Energy received $10 million in dividends from UNS Gas in the first six months of both 2013 and 2012.

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. As of June 30, 2013, 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 Credit Agreement and UNS Gas/UNS Electric Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Gas, and UNS Electric 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, below.

UNS Energy Consolidated Cash Flows

	Six months ended June 30,
	2013			2012
	Millions of Dollars
Operating Activities	$	148		$	113
Investing Activities	(150		)	(134		)
Financing Activities	(52		)	45

UNS Energy’s operating cash flows are generated primarily by retail and wholesale energy sales at TEP, UNS Gas, and UNS Electric, 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. TEP, UNS Gas, and UNS Electric typically use their revolving credit facilities to assist in funding their business activities during periods when sales are seasonally lower.

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Capital expenditures at TEP, UNS Gas, and UNS Electric 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 2013, net cash flows from operating activities were $35 million higher than they were in the same period last year. The following items affected the year-over-year change in operating cash flows: an increase in cash receipts from retail sales related to an increase in sales volumes from cold weather during the first three months of 2013, as well as an increase in TEP's PPFAC rate that became effective in April 2012; an increase in cash receipts from wholesale sales due in part to higher market prices for wholesale power; lower O&M costs due in part to a reduction in customer rebates for DSM programs to meet the ACC's Electric EE Standards; lower interest paid on capital lease obligations due to a decline in the balance of capital lease obligations; and various timing differences.

Investing Activities

Net cash flows used for investing activities increased by $16 million in the first six months of 2013 compared with the same period last year due in part to lower proceeds from investments in Springerville lease debt and an increase in REC purchases due to an increase in renewable energy PPAs.

Capital Expenditures

	Actual  Year-to-Date		Full Year Estimate
	June 30, 2013		2013
	Millions of Dollars
TEP	$	118	$	281
UNS Gas	9		16
UNS Electric	29		50
UNS Energy Consolidated	$	156	$	347

Financing Activities

Net cash flows used for financing activities were $97 million higher in the first six months of 2013 compared with the same period last year due to: an increase in scheduled capital lease payments; an increase in dividends paid on common stock; and a decrease in proceeds from borrowings (net of repayments) under revolving credit facilities.

UNS Credit Agreement

The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. As of June 30, 2013, there was $69 million outstanding at a weighted-average interest rate of 1.69%. 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.

As of June 30, 2013, we were in compliance with the terms of the UNS Credit Agreement.

Convertible Senior Notes

In March 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. In the first half of 2012, holders of approximately $147 million of the Convertible Senior Notes outstanding converted their interests into approximately 4.3 million shares of Common Stock. The remaining $3 million of outstanding Convertible Senior Notes were redeemed at par for cash.

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

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interest on borrowings under its revolving credit facility if London Interbank Offered Rate (LIBOR) and other benchmark interest rates increase. See Item 3. Quantitative and Qualitative Disclosures about Market Risk, below.

Contractual Obligations

There are no changes in our contractual obligations or other commercial commitments from those reported in our 2012 Annual Report on Form 10-K, other than the following changes in 2013:

• Fuel Obligations - We entered into new forward fuel commitments with minimum payment obligations of $3 million in 2014, $2 million in 2015 and $1 million in 2016.

• Purchase Power Obligations - We entered into new forward purchase power commitments with minimum payment obligations of $13 million in 2014 and $3 million in 2015. TEP also has a 20-year Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $4 million per year in each of the next five years and $56 million total thereafter.

• RES Performance-Based Incentives - We entered into new purchase agreements to purchase the environmental attributes, or Renewable Energy Credits (RECs), from retail customers with solar installations. Payments for these RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals, usually quarterly, based on metered renewable energy production over periods ranging from 9 to 20 years. Our total obligation related to RES PBI payments over future periods increased by $5 million from $68 million on December 31, 2012, to $73 million on June 30, 2013. PBIs are recoverable through the RES tariff. See Note 4.

• In March 2013, $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.0% and are due in September 2029. Proceeds were used to redeem $91 million of 2008 Pima Bonds bearing interest at a rate of 6.375% with the same maturity date. As a result, our interest obligations decreased by about $2 million per year. See Note 5.

• In the first quarter of 2013, we reduced unrecognized tax benefits by $28 million based on a favorable ruling from the Internal Revenue Service allowing us to deduct, rather than defer and amortize, up-front incentive payments to customers who install renewable energy resources. See Note 6.

Dividends on Common Stock

The following table shows the dividends declared to UNS Energy shareholders for 2013:

Declaration Date	Record Date	Payment Date	Dividend Amount Per Share  of Common Stock
February 25, 2013	March 13, 2013	March 25, 2013	$	0.435
May 2, 2013	June 7, 2013	June 26, 2013	$	0.435

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 during 2012 and 2013 eligible for 50% 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. As a result of these provisions, UNS Energy and TEP do not expect to pay any federal or state income taxes through 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.

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Second quarter of 2013 compared with the second quarter of 2012

TEP reported net income of $31 million in the second quarter of 2013 compared with net income of $22 million in the second quarter of 2012. The following factors affected TEP’s results in the second quarter of 2013:

• 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 $1 million decrease in interest expense due to a decline in the balance of capital lease obligations; and

• an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. See Note 6.

partially offset by:

• a $1 million decrease in retail margin revenues. Mild weather during April and May contributed to a 1.3% decrease in retail kilowatt-hour (kWh) sales;

• a one-time charge of $3 million recorded to fuel and purchased energy expense resulting from the 2013 TEP Rate Order. See Factors Affecting Results of Operations, Purchased Power and Fuel Adjustor Clause, below;

• a $1 million increase in Base O&M due in part to unplanned generating plant maintenance; and

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

Six months ended June 30, 2013 compared with six months ended June 30, 2012

TEP reported net income of $32 million in the first six months of 2013 compared with net income of $20 million in the first six months of 2012. The following factors affected TEP’s results in the first six months of 2013:

• a $3 million increase in retail margin revenues. A 29% increase in Heating Degree Days in the first quarter of 2013 contributed to a 1.1% increase in retail kilowatt-hour (kWh) sales during first six months of 2013;

• 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;

• a $4 million decrease in interest expense due to a decline in the balance of capital lease obligations; and

• an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. See Note 6.

partially offset by:

• a one-time charge of $3 million recorded to fuel and purchased energy expense resulting from the 2013 TEP Rate Order. See Factors Affecting Results of Operations, Purchased Power and Fuel Adjustor Clause, below;

• a $2 million increase in Base O&M due in part to unplanned generating plant maintenance;

• a $1 million increase in depreciation and amortization expense as a result of an increase in net plant-in-service; and

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

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Utility Sales and Revenues

Changes in the number of customers, weather, economic conditions, and other factors affect retail sales of electricity. The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the second quarters of 2013 and 2012:

	Three Months Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent(1)
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	1,002		1,022		(20		)	(2.0	)%
Commercial	537		539		(2		)	(0.3	)%
Industrial	543		544		(1		)	(0.2	)%
Mining	258		270		(12		)	(4.2	)%
Public Authorities	70		65		5			6.6	%
Total Electric Retail Sales	2,410		2,440		(30		)	(1.3	)%
Retail Margin Revenues (in Millions):
Residential	$	65	$	67	$	(2	)	(2.1	)%
Commercial	44		44		—			(0.5	)%
Industrial	24		24		—			0.8	%
Mining	8		8		—			—	%
Public Authorities	4		3		1			9.1	%
Total Retail Margin Revenues (Non-GAAP)(2)	145		146		(1		)	(0.8	)%
Fuel and Purchased Power Revenues	87		92		(5		)	(5.8	)%
RES & DSM Revenues	12		10		2			(22.9	)%
Total Retail Revenues (GAAP)	$	244	$	248	$	(4	)	(1.7	)%
Average Retail Margin Rate (Cents / kWh):(1)
Residential	6.54		6.54		—			—	%
Commercial	8.20		8.21		(0.01		)	(0.1	)%
Industrial	4.44		4.40		0.04			0.9	%
Mining	3.09		2.97		0.12			4.0	%
Public Authorities	5.16		5.04		0.12			2.4	%
Average Retail Margin Revenue	6.03		6.00		0.03			0.5	%
Average Fuel and Purchased Power Revenue	3.59		3.77		(0.18		)	(4.8	)%
Average RES & DSM Revenue	0.49		0.39		0.10			25.6	%
Total Average Retail Revenue	10.11		10.16		(0.05		)	(0.5	)%
Weather Data:
Cooling Degree Days
Three Months Ended June 30,	577		566		11			1.9	%
10-Year Average	463		452		NM			NM
Wholesale Energy Market Indicators:
Power Prices ($ / MWh) (3)	$	37.70	$	25.62	$	12.08		47.2	%
Natural Gas Prices ($ / MMBtu) (4)	3.84		2.19		1.65			75.3	%

⁽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.

⁽³⁾  On-peak market price of energy is based on the Dow Jones Palo Verde Index.

⁽⁴⁾  Average market price for natural gas is based on the Permian Index.

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Residential

Residential kWh sales were 2.0% lower in the second quarter of 2013 than they were during the same period last year, leading to a decrease in residential margin revenues of 2.1%, or $2 million. Residential use per customer decreased by 2.7% due in part to fewer cooling-degree days during April and May compared with last year. The average number of residential customers grew by 0.7% in the second quarter of 2013 compared with the same period last year.

Commercial

Commercial kWh sales decreased by 0.3% compared with the second quarter of 2012, leading to a decrease in commercial margin revenues of 0.5%, or less than $1 million. Commercial use per customer decreased by 0.4% due in part to fewer cooling-degree days during April and May compared with last year. The average number of commercial customers grew by 0.1% in the second quarter of 2013 compared with the same period last year.

Industrial

Industrial kWh sales decreased by 0.2% compared with the second quarter of 2012, and industrial margin revenues increased by 0.8% when compared with the same period in 2012. The increase in industrial retail margins resulted from a change in usage patterns by certain industrial customers that increased their demand charges paid to TEP.

Mining

Mining kWh sales decreased by 4.2% compared with the second quarter of 2012. One of TEP's mining customers performed maintenance on its facilities resulting in a temporary decrease in production. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

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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 2013 and 2012:

	Six Months Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent(1)
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	1,795		1,753		42			2.4	%
Commercial	939		934		5			0.6	%
Industrial	1,016		1,012		4			0.3	%
Mining	528		543		(15		)	(2.7	)%
Public Authorities	127		116		11			9.4	%
Total Electric Retail Sales	4,405		4,358		47			1.1	%
Retail Margin Revenues (in Millions):
Residential	$	116	$	113	$	3		2.2	%
Commercial	75		75		—			0.5	%
Industrial	44		44		—			—	%
Mining	14		14		—			—	%
Public Authorities	6		6		—			8.6	%
Total Retail Margin Revenues (Non-GAAP)(2)	255		252		3			1.4	%
Fuel and Purchased Power Revenues	151		141		10			7.0	%
RES & DSM Revenues	23		21		2			5.6	%
Total Retail Revenues (GAAP)	$	429	$	414	$	15		3.5	%
Average Retail Margin Rate (Cents / kWh):(1)
Residential	6.44		6.45		(0.01		)	(0.2	)%
Commercial	8.02		8.02		—			—	%
Industrial	4.28		4.30		(0.02		)	(0.5	)%
Mining	2.75		2.67		0.08			3.0	%
Public Authorities	4.98		5.02		(0.04		)	(0.8	)%
Average Retail Margin Revenue	5.79		5.78		0.01			0.2	%
Average Fuel and Purchased Power Revenue	3.42		3.24		0.18			5.6	%
Average RES & DSM Revenue	0.51		0.49		0.02			4.1	%
Total Average Retail Revenue	9.72		9.51		0.21			2.2	%
					Increase (Decrease)
Weather Data:	2013		2012		Amount			Percent(1)
Cooling Degree Days
Six Months Ended June 30,	577		566		11			1.9	%
10-Year Average	464		453		NM			NM
Wholesale Energy Market Indicators:
Power Prices ($ / MWh) (3)	$	34.85	$	25.31	$	9.54		37.7	%
Natural Gas Prices ($ / MMBtu) (4)	3.63		2.29		1.34			58.5	%

⁽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.

⁽³⁾  On-peak market price of energy is based on the Dow Jones Palo Verde Index.

⁽⁴⁾  Average market price for natural gas is based on the Permian Index.

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Residential

Residential kWh sales were 2.4% higher in the first six months of 2013 than they were during the same period last year, leading to an increase in residential margin revenues of 2.2%, or $3 million. Residential use per customer increased by 1.7% due in part to a 29.0% increase in Heating Degree Days during the first quarter. The average number of residential customers grew by 0.7% in the first six months of 2013 compared with the same period last year.

Commercial

Commercial kWh sales increased by 0.6% compared with the first six months of 2012, leading to an increase in commercial margin revenues of 0.5%, or less than $1 million. Commercial use per customer increased by 0.5% due in part to a 29.0% increase in Heating Degree Days during the first quarter. The average number of commercial customers increased by 0.1% in the first six months of 2013 when compared with the same period last year.

Industrial

Industrial kWh sales increased by 0.3% compared with the first six months of 2012, while industrial margin revenues were the same when compared with the same period in 2012.

Mining

Mining kWh sales decreased by 2.7% compared with the first six months of 2012. One of TEP's mining customers performed maintenance on its facilities resulting in a temporary decrease in production. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

Wholesale Sales and Transmission Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)	$	1	$	—	$	4	$	2
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues	4		5		9		10
Total Long-Term Wholesale Revenues	5		5		13		12
Transmission Revenues	4		4		8		8
Short-Term Wholesale Revenues	21		13		43		32
Electric Wholesale Sales (GAAP)	$	30	$	22	$	64	$	52

⁽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 second quarter and first six months of 2013 were higher than the same periods in 2012 due in part to higher market prices for wholesale power. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, below, for more information.

Short-Term Wholesale Revenues

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 Purchased Power and Fuel Adjustment Clause (PPFAC).

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Other Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
Revenue related to Springerville Units 3 and 4(1)	$	24	$	21	$	45	$	43
Other Revenue	7		8		15		14
Total Other Revenue	$	31	$	29	$	60	$	57

⁽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.

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

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for the three and six months ended June 30,2013 and 2012 are detailed below:

	Generation and Purchased Power				Fuel and Purchased Power Expense
	Three Months Ended June 30,
	2013		2012		2013		2012
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	2,639		2,332		$	71	$	60
Gas-Fired Generation	232		405		12		18
Renewable Generation	13		13		—		—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		2		2
Total Fuel	2,884		2,750		85		80
Total Purchased Power	544		649		28		21
Transmission	—		—		2		1
Increase to Reflect PPFAC Recovery Treatment	—		—		5		13
Total Resources	3,428		3,399		$	120	$	115
Less Line Losses and Company Use	(248	)	(233	)
Total Energy Sold	3,180		3,166

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	Generation and Purchased Power				Fuel and Purchased Power Expense
	Six Months Ended June 30,
	2013		2012		2013		2012
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	5,110		4,670		$	142	$	118
Gas-Fired Generation	418		695		20		28
Renewable Generation	24		25		—		—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		3		4
Total Fuel	5,552		5,390		165		150
Total Purchased Power	973		1,095		47		35
Transmission	—		—		3		2
Increase to Reflect PPFAC Recovery Treatment	—		—		3		5
Total Resources	6,525		6,485		$	218	$	192
Less Line Losses and Company Use	(420	)	(426	)
Total Energy Sold	6,105		6,059

Generation

Total generating output increased during the first six months of 2013 when compared with the same period last year due in part to higher retail kWh sales than the same period last year. Coal-fired generation increased by 9.4% during the first six months of 2013 when compared with the same period last year due in part to the use of coal to fuel Sundt Generating Station (Sundt) Unit 4 instead of natural gas.

Purchased Power

Purchased power volumes decreased during the first six months of2013 compared with the same period last year due in part to higher output from TEP's generating facilities.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
	cents per kWh		cents per kWh
Coal	2.71	2.57	2.78	2.51
Gas	4.99	4.30	4.71	4.05
Purchased Power	5.22	3.22	4.87	3.15
All Sources	3.61	3.22	3.53	3.08

O&M

The table below summarizes the items included in TEP’s O&M expense.

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	Millions of Dollars						Millions of Dollars
Base O&M (Non-GAAP)(1)	$	61		$	60		$	122		$	120
O&M Recorded in Other Expense	(1		)	(1		)	(3		)	(3		)
Reimbursed Expenses Related to Springerville Units 3 and 4	16			13			30			27
Expenses Related to Customer Funded Renewable Energy and DSM Programs(2)	6			7			11			17
Total O&M (GAAP)	$	82		$	79		$	160		$	161

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⁽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.

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 TEP Rate Order

In June 2013, the ACC issued an order (2013 TEP Rate Order) that resolved the rate case filed by TEP in July 2012. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

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

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

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

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

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

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

• a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant 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; and

• an agreement by TEP to seek recovery of costs related to the Nogales transmission line from the Federal Energy Regulatory Commission before seeking rate recovery from the ACC.

The 2013 TEP Rate Order also approved:

• A Lost Fixed Cost Recovery mechanism (LFCR) that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to energy efficiency programs and distributed generation. The LFCR rate will be adjusted annually and is subject to ACC approval and a year-over-year cap of 1% of TEP's total retail revenues. TEP expects to file its first LFCR report on or before May 15, 2014. That report will provide an estimate of certain unrecovered non-fuel costs incurred during the calendar year of 2013. TEP expects the new LFCR rate to become effective on July 1, 2014. We estimate that the LFCR could benefit pre-tax income by $2 million to $3 million in 2014.

• An Environmental Compliance Adjustor (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 expects to file its first ECA report on or before March 1, 2014. That report will include qualified investments and costs to be included in the ECA. TEP expects the new ECA rate to become effective on May 1, 2014. We estimate that the ECA could benefit pre-tax income by less than $1 million in 2014.

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

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• A new rate under TEP's Purchased Power and Fuel Adjustment Clause (PPFAC). See Purchased Power and Fuel Adjustment Clause, below.

Competition

Retail Electric Competition Rules

In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona.  Certain portions of the ACC Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004.  During 2012, a small number of companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP's service territory as an ESP.  Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP's retail customers to use an alternative ESP.

In May 2013, the ACC voted to commence a process to consider the possibility of opening Arizona to retail electric competition. The first step in the process was to solicit comments on questions raised by the ACC on the potential benefits and risks to Arizona electric customers associated with retail electric competition. On July 15, 2013, various parties, including TEP and UNS Electric, filed comments. TEP and UNS Electric oppose opening Arizona to retail electric competition. Responsive comments from the parties are due on August 16, 2013. The ACC is expected to schedule an open meeting before the end of 2013 to discuss these comments and possibly determine whether to proceed with the development of retail electric competition rules. If the ACC votes to proceed, it will then request interested parties to propose rules that would govern a competitive retail electric market.  We cannot predict the outcome of this matter.

Technological Developments and Energy Efficiency

New technological developments and the implementation of Electric EE Standards may reduce energy consumption by TEP's retail customers. TEP's customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP's services. In the wholesale market, TEP competes with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy.

Coal-Fired Generating Resources

As of June 30, 2013, approximately 70% of TEP's generating capacity was fueled by coal (of which 156 MW can be generated by natural gas or coal). 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 Note 4); and

• TEP's pending decision regarding its purchase options related to Springerville Unit 1 (see Springerville Unit 1, below).

Springerville Unit 1

TEP leases 86% of Springerville Unit 1 and owns the remaining 14%. The terms of the leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities (Springerville Unit 1 Leases), expire in 2015 but have optional fair market value renewal and purchase provisions. TEP has until August 31, 2013 to give notice that it will exercise its purchase option, with the purchase occurring in January 2015. TEP can choose to exercise the option to purchase any or all of the lease interests not currently owned by TEP.

In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure to determine the fair market value purchase price. The formal appraisal process was completed in accordance with the Springerville Unit 1 lease agreements. The purchase price was determined to be $478 per kW of capacity based on a continuous capacity rating of 387 MW. If TEP chooses to purchase all of the remaining interests in Springerville Unit 1 from the owner participants, the aggregate purchase price would be $159 million. See Item 1. - Legal Proceedings, Springerville Unit 1 Appraisal.

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Purchased Power and Fuel Adjustment Clause

In March 2012, the ACC approved a PPFAC rate of 0.77 cents per kWh effective April 2012 to recover $77 million of under-collected fuel and purchased power costs. At June 30, 2013, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $5 million.

The 2013 TEP Rate Order approved a new PPFAC rate, which includes:

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

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

TEP's existing PPFAC mechanism will continue with certain modifications, including the recovery of the following costs and/or credits: lime costs; Sulfur Credits; broker fees; and 100% of the proceeds from the sale of SO₂ allowances.

Beginning on July 1, 2013, TEP's PPFAC rate was a credit to retail customers of approximately 0.14 cents per kWh. This PPFAC rate will be in effect until the rate is reset by the ACC in the second quarter of 2014. TEP's PPFAC includes the recovery of lime costs (lime is used to control SO₂ emissions), net of Sulfur Credits received from TEP's coal suppliers. TEP estimates that from July 1 to December 31, 2013, approximately $5 million of net lime expense will be recorded in fuel and purchased energy expense and recovered through the PPFAC. Prior to July 1, 2013, lime costs were recorded in operations and maintenance expense.  

Springerville Units 3 and 4

TEP operates and 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,
	2013			2012			2013			2012
	Millions of Dollars						Millions of Dollars
Other Revenues	$	24		$	21		$	45		$	43
Fuel Expense	(2		)	(2		)	(3		)	(4		)
O&M Expense	(16		)	(13		)	(30		)	(27		)
Taxes Other Than Income Taxes	—			—			(1		)	(1		)
Total Pre-Tax Income	$	6		$	6		$	11		$	11

Pension and Retiree Benefit Expense

The table below summarizes TEP’s pension and other retiree benefit expenses charged to O&M in 2013 and 2012. See Note 7.

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
Pension Expense Charged to O&M	$	3	$	3	$	5	$	5
Retiree Benefit Expense Charged to O&M	1		1		2		2
Total	$	4	$	4	$	7	$	7

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Long-Term Wholesale Sales

TEP’s two primary long-term wholesale contracts are with SRP and the Navajo Tribal Utility Authority (NTUA).

Salt River Project

From January 1, 2012, through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the price of on-peak power on the Dow Jones Palo Verde Market Index.

Navajo Tribal Utility Authority

TEP serves the portion of NTUA's load that is not served from NTUA's allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh. Prior to June 30, 2013, the power sold to NTUA was at a fixed price.  In May 2013, TEP amended its contract with NTUA.

Beginning July 1, 2013, TEP receives monthly capacity payments in exchange for providing 15 MW from July to September (June to September beginning in 2014 and thereafter) and 50 MW for the remainder of the year. Starting in 2016, the July to September capacity increases to 25 MW. Any energy sold above those amounts will be indexed to the wholesale market price of natural gas.  TEP's contract with NTUA was extended from December 2015 to December 2022.  TEP estimates that sales to NTUA will be approximately 225,000 MWh in 2013 and 2014.

Long-Term Wholesale Margin and Sensitivity

TEP’s margin on long-term wholesale sales was $4 million during the first six months of 2013 and $2 million during the same period last year.

As of July 17, 2013, the average forward price of on-peak power on the Dow Jones Palo Verde Market Index for the remainder of calendar year 2013 was $38 per MWh; the average price of on-peak power during the first six months of 2013 was $35 per MWh. A change of $5 per MWh in the on-peak market price of power on the Dow Jones Palo Verde Market Index for the balance of the year would change 2013 pre-tax income related to the SRP contract by approximately $2 million.

Electric Energy Efficiency Standards

In August 2010, the ACC approved new Electric Energy Efficiency Standards (Electric EE Standards) designed to require TEP, UNS Electric, and other affected electric utilities to implement cost-effective programs to reduce customers' energy consumption. In 2013, the Electric EE Standards target total kWh savings of 5% of 2012 retail kWh sales; in 2014, the Electric EE Standards target total kWh savings of 7.25% of 2013 retail kWh sales. The Electric EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.

DSM programs approved by the ACC, direct load control programs, and energy efficient building codes are acceptable means to meet the Electric EE Standards as set forth by the ACC.

As part of the 2013 TEP Rate Order, the ACC approved a 2013 calendar year energy efficiency budget of $21 million, which includes a performance incentive of approximately $1 million which may be recognized in 2013. The Electric EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP's programs, and the rates charged to customers for such programs, are subject to annual review and approval by the ACC. See2013 TEP Rate Order above.

Renewable Energy Standard and Tariff

In January 2013, the ACC approved TEP's 2013 RES implementation plan. Under the plan, TEP expects to collect approximately $36 million from retail customers during 2013. The plan includes an investment of $28 million in 2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $3 million pre-tax in 2013 on solar investments made in 2010, 2011, and 2012. TEP expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales.

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Sales to Mining Customers

Copper prices have triggered an increase in mining activity at the copper mines operating in TEP's service area. 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 100 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 Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line for the construction and ongoing operation of the mine. The state line siting committee approved a certificate of environmental compatibility (CEC) in 2011 for the 138 kV transmission line. In 2012, the ACC finalized the CEC. 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.

Interest Rates

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under its revolving credit facility. At June 30, 2013, TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds is 10% on $37 million of bonds and 20% on the other $178 million. During the first six months of 2013, the average rates paid ranged from 0.08% to 0.25%. At July 17, 2013, the average rate on the debt was 0.07%.

TEP has a fixed-for-floating interest rate swap to hedge $50 million of its tax-exempt variable rate debt.

TEP is also 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. If LIBOR and other benchmark interest rates increase, TEP may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 3. Quantitative and Qualitative Disclosures about Market Risk, below.

Fair Value Measurements

TEP’s income statement exposure to energy price risk is mitigated as TEP reports the change in fair value of energy contract derivatives as either a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement. See Note 11.

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LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

The tables below show the cash flow realized by TEP after capital expenditures and payments on capital lease obligations:

	Six Months Ended June 30,
	2013			2012
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	116		$	67
Amounts from Statements of Cash Flows:
Less: Capital Expenditures	(118		)	(142		)
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)	(2		)	(75		)
Amounts From Statements of Cash Flows:
Less: Payments for Capital Lease Obligations	(84		)	(76		)
Plus: Proceeds from Investment in Lease Debt	9			19
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)(1)	$	(77	)	$	(132	)

	Six Months Ended June 30,
	2013			2012
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	116		$	67
Net Cash Flows – Investing Activities (GAAP)	(113		)	(117		)
Net Cash Flows – Financing Activities (GAAP)	(55		)	55
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)	(2		)	(75		)
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)(1)	(77		)	(132		)

⁽¹⁾  Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on 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 Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make required payments on capital lease obligations, and pay dividends to UNS Energy before consideration of financing activities.

Liquidity Outlook

During 2013, TEP expects to generate sufficient operating cash flows to fund the majority of its capital expenditures. 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.

Operating Activities

In the first six months of 2013, net cash flows from operating activities were $49 million higher than in the first six months of 2012. The increase was due in part to: higher cash receipts from retail sales related to an increase in sales volumes from cold weather during the first three months of 2013, as well as an increase in TEP's PPFAC rate that became effective in April 2012; an increase in cash receipts from wholesale sales due in part to higher market prices for wholesale power; a decrease in capital lease interest paid due to a decline in capital lease obligation balances; lower O&M costs due in part to a reduction in customer rebates for DSM programs to meet the ACC's Electric EE Standards; and various timing differences.

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Investing Activities

Net cash flows used for investing activities decreased by $4 million in the first six months of 2013 compared with the same period last year due primarily to lower capital expenditures partially offset by lower proceeds from the investment in lease debt and an increase in purchases of RECs due to an increase in renewable energy PPAs.

TEP’s capital expenditures were $118 million in the first six months of 2013 compared with $142 million in the same period last year. TEP’s estimated capital expenditures for 2013 are $281 million.

Financing Activities

In the first six months of 2013, net cash from financing activities was $110 million lower than in the same period in 2012 due to a $109 million decrease in borrowings (net of repayments) made under TEP’s Revolving Credit Facility.

TEP Credit Agreement

The TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $186 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016 and is secured by $386 million of Mortgage Bonds. As of June 30, 2013, there were $30 million of outstanding borrowings and $1 million of LOCs issued under the TEP Revolving Credit Facility.

The TEP Credit Agreement contains restrictions on liens, 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. As of June 30, 2013, TEP was in compliance with the terms of the TEP Credit Agreement.

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.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of June 30, 2013, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

2013 Bond Issuances and Redemptions

In March 2013, approximately $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029 and may be redeemed at par on or after March 1, 2023. In April 2013, the proceeds of the bond issuance were used to redeem approximately $91 million of unsecured tax-exempt bonds with an interest rate of 6.375% and a maturity date of September 2029. See Note 5.

Capital Lease Obligations

As of June 30, 2013, TEP had $277 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, 2013		Expiration	Renewal/Purchase Option
	Millions of Dollars
Springerville Unit 1(1)	$	138	2015	Fair market value purchase option of $159 million(2)
Springerville Coal Handling Facilities Lease	43		2015	Fixed price purchase option of $120 million(3)
Springerville Common Facilities(4)	96		2017 and 2021	Fixed price purchase option of $106 million(3)
Total Capital Lease Obligations	$	277

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⁽¹⁾  The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities.

⁽²⁾  As determined in December 2011 in an appraisal procedure undertaken pursuant to the Springerville Unit 1 lease agreements. See Part II, Item 1.—Legal Proceedings.

⁽³⁾  TEP 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 and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri State will then be obligated to either 1) buy a portion of these facilities; or 2) continue making payments to TEP for the use of these facilities.

⁽⁴⁾  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, above.

Contractual Obligations

There have been no changes in TEP’s contractual obligations or other commercial commitments from those reported in our 2012 Annual Report on Form 10-K, other than the following changes in 2013:

• TEP entered into new forward purchase power commitments that will settle through December 2014. Some of these contracts are at fixed prices per MWh and others are indexed to natural gas prices. Based on projected market prices as of March 31, 2013, TEP's estimated minimum payment obligations for these additional purchases are $9 million in 2014. TEP also has a 20-year Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $4 million per year in each of the next five years and approximately $56 million total thereafter.

• TEP is contractually obligated to retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In the first quarter of 2013, TEP's total obligation for RES PBIs increased by $4 million dollars from $62 million on December 31, 2012, to $66 million on June 30, 2013. TEP will make required payments over periods ranging from 9 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 4.

• In March 2013, $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.0% and are due in September 2029. Proceeds were used to redeem $91 million of 2008 Pima Bonds bearing interest at a rate of 6.375% with the same maturity date. As a result, TEP's interest obligations decreased by about $2 million per year. See Note 5.

• In the first quarter of 2013, TEP reduced unrecognized tax benefits by $22 million based on a favorable ruling from the Internal Revenue Service allowing us to deduct, rather than defer and amortize, up-front incentive payments to customers who install renewable energy resources. See Note 6.

Dividends on Common Stock

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement. As of June 30, 2013, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement.

The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year earnings.

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported no net income in the second quarters of 2013 and 2012. In the first six months of 2013, UNS Gas reported net income of $8 million compared with net income of $5 million in the same period last year. The increase in net income for the six months ended June 30 is due primarily to: cold weather in the first quarter, which contributed to a 10.0% increase in

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retail therm sales in the first six months of 2013 relative to 2012; and a non-fuel base rate increase that was effective in May 2012.

The table below provides summary financial information for UNS Gas:

	Three Months Ended June 30,					Six Months Ended June 30,
	2013			2012		2013			2012
	Millions of Dollars					Millions of Dollars
Gas Revenues	$	22		$	21	$	73		$	72
Other Revenues	—			1		1			3
Total Operating Revenues	22			22		74			75
Purchased Gas Expense	12			10		42			40
Increase (Decrease) to Reflect PGA Recovery Treatment	(1		)	1		(2		)	3
O&M	6			6		12			13
Depreciation and Amortization	2			2		4			5
Taxes Other Than Income Taxes	1			1		2			2
Total Other Operating Expenses	20			20		58			63
Operating Income	2			2		16			12
Interest Expense	2			2		3			3
Income Tax Expense	—			—		5			4
Net Income	$	—		$	—	$	8		$	5

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The table below includes UNS Gas’ therm sales and margin revenues for the second quarters of 2013 and 2012:

	Three Months Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent(1)
Gas Retail Sales, Therms (in Millions):
Residential	9		9		—			2.3	%
Commercial	5		5		—			2.5	%
Industrial	—		—		—			19.9	%
Public Authorities	1		1		—			9.7	%
Total Gas Retail Sales	15		15		—			3.2	%
Negotiated Sales Program (NSP)	7		8		(1		)	(18.6	)%
Total Gas Sales	22		23		(1		)	(4.8	)%
Retail Margin Revenues (in Millions):
Residential	$	7	$	7	$	—		2.9	%
Commercial	2		2		—			—	%
Public Authorities	1		—		1			7.3	%
Total Retail Margin Revenues (Non-GAAP)(2)	10		9		1			2.9	%
Transport and NSP	4		4		—			17.5	%
Retail Fuel Revenues	8		8		—			(7.2	)%
Total Gas Revenues (GAAP)	$	22	$	21	$	1		1.6	%
Weather Data:
Heating Degree Days
Three Months Ended June 30,	480		437		43			9.8	%
10-Year Average	560		551		NM			NM

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

⁽²⁾  Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total 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 during the second quarter of 2013 increased by 3.2% due in part to a 9.8% increase in Heating Degree Days. The increase in retail therm sales, as well as a Base Rate increase implemented in May 2012, contributed to an increase in retail margin revenues of 2.9%, or $1 million, compared with the second quarter of 2012.

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.

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The table below includes UNS Gas’ therm sales and margin revenues for the first six months of 2013 and 2012:

	Six Months Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent(1)
Gas Retail Sales, Therms (in Millions):
Residential	44		39		5			11.0	%
Commercial	17		16		1			6.8	%
Industrial	1		1		—			19.4	%
Public Authorities	4		4		—			10.1	%
Total Gas Retail Sales	66		60		6			10.0	%
Negotiated Sales Program (NSP)	13		15		(2		)	(10.6	)%
Total Gas Sales	79		75		4			5.8	%
Retail Margin Revenues (in Millions):
Residential	$	23	$	21	$	2		10.1	%
Commercial	6		6		—			8.9	%
Public Authorities	1		1		—			14.3	%
Total Retail Margin Revenues (Non-GAAP)(2)	30		28		2			10.1	%
Transport and NSP	9		7		2			17.6	%
Retail Fuel Revenues	34		37		(3		)	(7.9	)%
Total Gas Revenues (GAAP)	$	73	$	72	$	1		1.8	%
Weather Data:
Heating Degree Days
Six Months Ended June 30,	2,668		2,450		218			8.9	%
10-Year Average	2,643		2,654		NM			NM

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

⁽²⁾  Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total 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 during the first six months of 2013 increased by 10.0% due in part to an 8.9% increase in Heating Degree Days. The increase in retail therm sales, as well as a Base Rate increase implemented in May 2012, contributed to an increase in retail margin revenues of 10.1%, or $2 million, compared with the same period in 2012.

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of the ACC’s Gas Energy Efficiency Standards (Gas EE Standards) may reduce energy consumption by UNS Gas’ retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas.

Rates

2012 UNS Gas Rate Order

In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as an LFCR mechanism to enable UNS Gas to recover lost fixed-cost revenues as a result of implementing the Gas EE Standards. The LFCR is expected to recover lost fixed-cost revenues of less than $0.1 million in 2014, based on estimated lost retail therm sales from May 2012 through December 2013.

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The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills was offset by a temporary credit adjustment to the PGA. See Purchased Gas Adjustor, below, for more information.

Purchased Gas Adjustor

The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered or returned to customers through the PGA mechanism.

The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that calculates the twelve-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a 12-month period. The annual cap on the maximum increase in the PGA factor is 15 cents per therm in a 12-month period.

At any time UNS Gas’ PGA balancing account, called the PGA bank balance, is under-recovered, UNS Gas may request a PGA surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed-to-customer basis, UNS Gas is required to make a filing with the ACC to determine how the over-collected balance should be returned to customers.

In April 2012, the ACC approved the temporary PGA credit adjustment of 4.5 cents per therm which became effective on May 1, 2012, and will continue through April 2014 or until the bank balance reaches zero. The credit adjustment over this period is expected to return approximately $10 million of over-collected PGA costs to customers. At June 30, 2013, the PGA bank balance was over-collected by $14 million on a billed-to-customer basis.

Gas Energy Efficiency Standards

In 2010, the ACC approved Gas EE Standards which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2012, the Gas EE Standards targeted total retail therm savings equal to 1.2% of 2011 sales; in 2013, the Gas EE Standards target total therm savings of 1.8% of 2012 retail therm sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020. UNS Gas' programs, during 2011 and 2012, saved cumulative energy equal to approximately 0.35% of its 2011 retail therm sales.

Existing DSM programs, renewable energy technology that displaces gas and certain energy efficient building codes are acceptable means to meet the Gas EE Standards. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas' DSM programs and rates charged to retail customers for these programs are subject to ACC approval.

In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011, which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Energy Efficiency plan or the subsequent requests.

Fair Value Measurements

UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas expects operating cash flows to fund all of its construction expenditures during 2013. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements in future periods. Sources of funding future capital expenditures could include existing cash balances, draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.

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Cash Flows and Capital Expenditures

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

	Six months ended June 30,
	2013			2012
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	17		$	21
Investing Activities	(8		)	(8		)
Financing Activities	(10		)	(10		)
Net Increase/(Decrease) in Cash	(1		)	3
Beginning Cash	31			38
Ending Cash	$	30		$	41

UNS Gas' operating cash flows during the first six months of 2013 were $4 million lower than the same period last year due in part to the PGA credit that was effective in April 2012 and higher volumes of gas purchased as a result of increased demand from a cold winter .

UNS Gas/UNS Electric Revolver

The UNS Gas/UNS Electric Revolver consists of a $100 million unsecured revolving credit and revolving letter of credit 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 Gas/UNS Electric Revolver expires November 2016.

UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver. As of June 30, 2013, UNS Gas had no outstanding borrowings or LOCs under the UNS Gas/UNS Electric Revolver.

The UNS Gas/UNS Electric Revolver 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. As of June 30, 2013, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.

Interest Rate Risk

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

Contractual Obligations

In 2013, UNS Gas entered into new forward energy commitments that settle through May 2016 at fixed prices per MMBtu. UNS Gas’ minimum payment obligations for these purchases are $3 million in 2014, $2 million in 2015, and $1 million in 2016. There have been no other significant changes in UNS Gas’ contractual obligations or other commercial commitments from those reported in our 2012 Annual Report on Form 10-K.

Dividends on Common Stock

UNS Gas paid dividends to UNS Energy, through UES, of $10 million during the first six months of 2013 and 2012. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (i) no default or event of default exists, (ii) it could incur additional debt under the debt incurrence test. As of June 30, 2013, 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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UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $4 million in the second quarters of 2013 and 2012. In the first six months of 2013, UNS Electric reported net income of $6 million compared with net income of $7 million in the same period last year.

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,
	2013			2012		2013			2012
	Millions of Dollars
Retail Electric Revenues	$	42		$	44	$	78		$	83
Wholesale Electric Revenues	2			4		3			8
Other Revenues	—			—		—			1
Total Operating Revenues	44			48		81			92
Purchased Energy Expense	20			19		37			37
Fuel Expense	2			3		3			4
Transmission Expense	3			3		6			5
Increase (Decrease) to Reflect PPFAC Recovery	(2		)	1		(4		)	3
O&M	7			7		15			16
Depreciation and Amortization Expense	5			5		9			9
Taxes Other Than Income Taxes	1			1		3			2
Total Other Operating Expenses	36			39		69			76
Operating Income	8			9		12			16
Interest Expense	2			2		3			4
Income Tax Expense	2			3		3			5
Net Income	$	4		$	4	$	6		$	7

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The table below shows UNS Electric’s kWh sales and revenues for the second quarters of 2013 and 2012:

	Three Months Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent(1)
Electric Retail Sales, kWh (in Millions):
Residential	201		205		(4		)	(1.6	)%
Commercial	170		167		3			1.2	%
Industrial	49		55		(6		)	(11.2	)%
Mining	16		28		(12		)	(41.9	)%
Public Authorities	—		—		—			(1.6	)%
Total Electric Retail Sales	436		455		(19		)	(4.2	)%
Retail Margin Revenues (in Millions):
Residential	$	8	$	8	$	—		(1.3	)%
Commercial	8		8		—			(1.3	)%
Industrial	2		2		—			(13.0	)%
Mining	1		2		(1		)	(41.2	)%
Public Authorities	—		—		—			—
Total Retail Margin Revenues (Non-GAAP)(2)	19		20		(1		)	(6.1	)%
Fuel and Purchased Power Revenues	21		22		(1		)	(2.8	)%
RES & DSM Revenues	2		2		—			(25.9	)%
Total Retail Revenues (GAAP)	$	42	$	44	$	(2	)	(5.6	)%
Weather Data:
Cooling Degree Days
Three Months Ended June 30,	1,221		1,227		(6		)	(0.5	)%
10-Year Average	1,029		1,056		NM			NM

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

⁽²⁾  Total 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. Total Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

Total retail kWh sales in the second quarter of 2013 decreased by 4.2% compared with the same period last year. Sales volumes to mining customers decreased by 41.9% in the second quarter of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Industrial kWh sales decreased by 11.2% due to the loss of a customer in the fourth quarter of 2012. Total Retail Margin Revenues in the second quarter of 2013 were similar to the level in the second quarter of 2012. See Factors Affecting Results of Operations, Large Customers, below.

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The table below shows UNS Electric’s kWh sales and revenues for the first six months of 2013 and 2012:

	Six Months Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent(1)
Electric Retail Sales, kWh (in Millions):
Residential	392		375		17			4.3	%
Commercial	297		299		(2		)	(0.5	)%
Industrial	91		108		(17		)	(15.7	)%
Mining	29		55		(26		)	(47.0	)%
Public Authorities	1		1		—			14.7	%
Total Electric Retail Sales	810		838		(28		)	(3.4	)%
Retail Margin Revenues (in Millions):
Residential	$	15	$	15	$	—		4.1	%
Commercial	14		14		—			(0.7	)%
Industrial	4		5		(1		)	(15.2	)%
Mining	3		3		—			(26.5	)%
Public Authorities	—		—		—			—
Total Retail Margin Revenues (Non-GAAP)(2)	36		37		(1		)	(3.0	)%
Fuel and Purchased Power Revenues	38		40		(2		)	(6.3	)%
RES & DSM Revenues	4		6		(2		)	(33.9	)%
Total Retail Revenues (GAAP)	$	78	$	83	$	(5	)	(6.7	)%
Weather Data:
Cooling Degree Days
Six Months Ended June 30,	1,304		1,274		30			2.4	%
10-Year Average	1,074		1,101		NM			NM

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

⁽²⁾  Total 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. Total Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

Total retail kWh sales in the first six months of 2013 decreased by 3.4% compared with the same period last year. Sales volumes to mining customers decreased by 47.0% in the first six months of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Industrial kWh sales decreased by 15.7% due to the loss of a customer in the fourth quarter of 2012. Total Retail Margin Revenues in the first six months of 2013 were similar to the level in the same period last year. See Factors Affecting Results of Operations, Large Customers, below.

FACTORS AFFECTING RESULTS OF OPERATIONS

2012 UNS Electric Rate Case

In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric's 2010 Rate Order.

The key provisions of UNS Electric's rate request are summarized below, as well as ACC Staff's testimony that was filed in June 2013.

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	UNS Electric Request	ACC Staff Testimony
Non-fuel Base Rate Increase and % Increase Over Adjusted Test Year Revenues	$7.5 million or 4.6%	$1.4 million or 0.8%
OCRB	$217 million, including $13 million of post test year adjustments	$212 million, including $8 million of post test year adjustments
FVRB	$286 million	$281 million
Fair Value Increment of Rate Base (the difference between FVRB and OCRB)	$69 million	$69 million
Capital Structure	47% debt / 53% equity	47% debt / 53% equity
Cost of Long-Term Debt	5.97%	5.97%
Return on Equity	10.50%	9.25%
Return on Fair Value Increment	1.61%	0.0% - 0.5%

UNS Electric is also seeking the approval of the cost recovery mechanisms described below.

Lost Fixed Cost Recovery Mechanism

UNS Electric proposed a LFCR mechanism that would allow UNS Electric to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to compliance with the ACC's Electric EE Standards and distributed generation requirements under the ACC's RES. The LFCR is not a full decoupling mechanism because it is not intended to recover lost fixed costs attributable to weather or economic conditions. In its testimony, ACC Staff recommended the approval of the LFCR.

Transmission Cost Adjustment Mechanism

UNS Electric proposed a Transmission Cost Adjustment Mechanism (TCA) that would allow UNS Electric to recover, on a more timely basis, transmission costs associated with serving retail customers. UNS Electric's proposed retail Base Rates include a transmission cost reflective of the current FERC rate. As the FERC rate changes, the TCA would result in a corresponding adjustment to the transmission component of retail Base Rates. In its testimony, ACC Staff recommended the approval of the TCA.

Energy Efficiency Resource Plan

UNS Electric proposed a three-year pilot program that would allow it to invest in energy efficiency programs in order to meet the ACC's Electric EE Standards in the most cost-effective manner. Electric EE Standards investments would be considered regulatory assets and amortized over a four-year period. UNS Electric would earn a return on its investments and recover the return and amortization expense through the existing demand-side management surcharge.

Status of Rate Request

Settlement discussions among the parties commenced on July 29, 2013. Hearings before an ACC administrative law judge are scheduled to begin in October 2013. UNS Electric requested that new rates be effective by January 1, 2014. We cannot predict the outcome of the settlement proceedings or whether UNS Electric's rate request will be adopted by the ACC in whole or in part.

Renewable Energy Standard and Tariff

As part of UNS Electric's rate order in 2010, the ACC authorized UNS Electric to recover operating costs, depreciation, property taxes, and a return on its investment in company-owned solar projects through RES funds until these costs are reflected in its Base Rates. Under these terms, UNS Electric expects to invest $5 million annually in 2013 and 2014 in solar photovoltaic projects.

In January 2013, the ACC approved UNS Electric's 2013 RES implementation plan. UNS Electric will collect approximately $7 million from customers during 2013, a portion of which is expected to provide recovery of operating costs and a return on investment to UNS Electric for company-owned solar projects.

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Electric Energy Efficiency Standards

In 2010, the ACC approved Electric EE Standards. See Tucson Electric Power, Factors Affecting Results of Operations, Electric Energy Efficiency Standards, above for more information.

In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC will issue a final order in this matter.

Competition

See Tucson Electric Power, Factors Affecting Results of Operations, Competition, above.

Large Customers

One of UNS Electric's mining customers began generating a portion of its own electricity needs in 2011. Due to UNS Electric's retail rate structure and the customer's peak electric demand, the margin revenues from this customer in 2012 were near the same level as 2011. Another large retail customer shut down its operations in UNS Electric's service territory. As a result of these two events, we estimate UNS Electric's non-residential retail margin revenues will be approximately $4 million lower in 2013 than in 2012.

Interest Rates

UNS Electric is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Electric may be required to pay higher rates of interest on borrowings under its revolving credit facility.

Fair Value Measurements

UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric expects operating cash flows to fund a large portion of its construction expenditures during 2013. Additional sources of funding capital expenditures could include draws on the UNS Gas/UNS Electric 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,
	2013			2012
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	12		$	26
Investing Activities	(30		)	(15		)
Financing Activities	14			—
Net Increase/(Decrease) in Cash	(4		)	11
Beginning Cash	8			5
Ending Cash	$	4		$	16

Operating Activities

Cash provided by operating activities decreased by $14 million in the first six months of 2013 compared with the same period in 2012 due to: a $9 million decrease in cash receipts from electric sales (net of fuel and purchased energy costs paid) due in part to a lower PPFAC rate that was effective in June 2012 and the loss of an industrial customer; and a $4 million increase in

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income taxes paid (net of income tax refunds received) due primarily to true-up payments related to estimated income tax payments made in 2012.

Investing Activities

UNS Electric had capital expenditures of $29 million in the first six months of 2013 compared with $16 million in the same period in 2012. The increase is related to a transmission line that is being constructed to increase reliability to UNS Electric's service territory in Nogales, Arizona. UNS Electric estimates total capital expenditures in 2013 of $50 million.

Financing Activities

Cash provided by financing activities at UNS Electric in the first six months of 2013 increased by $14 million when compared with the same period in 2012. Financing activities in 2013 included $12 million of borrowings under its revolving credit facility and a $2 million receipt related to a contribution in aid of construction from a large customer.

UNS Gas/UNS Electric Revolver

See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver above for a description of UNS Electric’s unsecured revolving credit agreement.

UNS Electric expects to draw upon the UNS Gas/UNS Electric 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. As of June 30, 2013, UNS Electric had $12 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Gas/UNS Electric Revolver.

Contractual Obligations

In 2013, UNS Electric entered into new forward purchase power commitments that will settle through September 2015 at fixed prices per MWh. UNS Electric’s estimated minimum payment obligations for these purchases are $4 million in 2014 and $3 million in 2015.

Additionally, UNS Electric is contractually obligated to retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In 2013, UNS Electric's total obligation for RES PBIs increased by approximately $1 million, from $6 million on December 31, 2012, to $7 million on June 30, 2013. PBIs are recoverable through the RES tariff. See Note 4.

There have been no other significant changes in UNS Electric’s contractual obligations or other commercial commitments from those reported in our 2012 Annual Report on Form 10-K.

Dividends on Common Stock

In the first six months of 2013, UNS Electric paid no dividends to UNS Energy. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (i) no default or event of default exists, and (ii) it could incur additional debt under the debt incurrence test. As of June 30, 2013, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Gas/UNS Electric Revolver.

CRITICAL ACCOUNTING ESTIMATES

Plant Asset Depreciable Lives

The 2013 TEP Rate Order approved a change in depreciation rates for generation and distribution plant from an average of 3.32% to 3.00% , effective July 1, 2013. The change in depreciation rates will have the effect of reducing depreciation expense by approximately $11 million annually.  The reduction in depreciation expense is primarily due to revised estimates of removal costs, net of estimated salvage value for interim and final retirements. See Note 2.

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT

The Financial Accounting Standards Board issued authoritative guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. Upon implementation entities will continue reporting their obligations under joint and several arrangements. In addition, the entity must measure, recognize, and disclose in the financial statements amounts they expect to pay on behalf of co-obligors for fixed obligations as of the balance sheet date. This guidance will be effective in the first quarter of 2014. 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.

PART II – OTHER INFORMATION

ITEM 1. – LEGAL PROCEEDINGS

See the legal proceedings described in Item 3. – Legal Proceedings in our 2012 Annual Report on Form 10-K and in Note 4 and in Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 4 and Item 2 are incorporated herein by reference.

Springerville Unit 1 Appraisal

Springerville Unit 1 is leased by TEP under leases which expire in 2015 and which provide TEP with an option to purchase the lease interests upon the lease expiration at fair market value. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure with three appraisers in accordance with the lease agreements to determine the fair market value purchase price. The lease agreements provide that the purchase price determined through the appraisal procedure will be final and binding upon the parties. The aggregate purchase price for the owner participants' lease interests was determined to be $159 million.

On April 26, 2012, TEP filed a petition to confirm the appraisal in the United States District Court for the District of Arizona naming the owner participants (Daimler Capital Services LLC, LDVFI TEP LLC, Alterna Springerville LLC, MWR Capital Inc., and Pacific Harbor Capital Inc.) and the owner trustee and co-trustee (Wilmington Trust Company and William J. Wade) as respondents. The petition states that TEP filed the petition since neither the owner participants nor the owner trustee and co-

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trustee have acknowledged that the purchase price determined by the appraisal procedure in December 2011 is final and binding and that TEP seeks an order from the court confirming the appraisal as an arbitration award under the Federal Arbitration Act (FAA).

On June 1, 2012, the owner participants filed a response in opposition to TEP's petition. In their response, the owner participants allege that the appraisal procedure failed to yield a legitimate purchase price for the lease interests, stating, among other things, that not all of the three appraisers performed their appraisals in accordance with required standards. The owner participants requested that the court dismiss the action and deny TEP's petition on the grounds that there is not a present controversy for the court to decide, since, among other things, TEP has not exercised the purchase option. The owner participants also dispute TEP's position that the appraisal procedure should be treated as an arbitration award for purposes of judicial review. In January 2013, the court denied TEP's petition on the grounds that the court is without jurisdiction under the FAA to confirm the appraisal.

On February 12, 2013, TEP appealed the matter to the United States Court of Appeals for the Ninth Circuit, where it is currently pending.

TEP believes that the appraisal procedure was properly conducted in accordance with the lease agreements and that the results are final and binding. TEP intends to continue vigorously pursuing its legal remedies to confirm the results of the appraisal procedure, if any purchase options are exercised.

Under the lease agreements, TEP has until August 31, 2013 to exercise its options to purchase one or more ownership interests in Springerville Unit 1.

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 2012 Annual Report on Form 10-K, other than as described below:

TEP, UNS Gas, and UNS Electric are subject to regulation by the ACC, which sets the companies' Retail Rates and oversees many aspects of their business in ways that could negatively affect the companies' results of operations, net income, and cash flows.

The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.

The ACC is charged with setting retail electric and gas rates that provide utility companies with an opportunity to recover their costs of service and earn a reasonable rate of return. The decisions these elected officials make on such matters impact the net income and cash flows of TEP, UNS Gas, and UNS Electric.

In May 2013, the ACC initiated an inquiry to discuss the possibility of opening Arizona to retail electric competition. If the ACC decides to implement retail electric competition in Arizona, it could negatively impact the results of operations, net income, and cash flows of TEP and UNS Electric.

Developments in technology could reduce the demand for electricity.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-owned generation, energy efficiency, and appliances and equipment.  Advances in these, or other technologies, could reduce the cost of producing electricity or make our existing generating facilities less economical.  In addition, advances in such technologies could reduce electricity demand, which could negatively impact the results of operations, net income, and cash flows of TEP and UNS Electric.

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ITEM 2. – UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

See Part I, Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Convertible Senior Notes.

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 7A in our Annual Report on Form 10-K for the year ended December 31, 2012, other than the following:

Commodity Price Risk—TEP

See Item 2. Management’s Discussion and Analysis, Tucson Electric Power, Factors Affecting Results of Operations, Long-Term Wholesale Sales, Long-Term Wholesale Margin and Sensitivity.

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 2013 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.

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, 2013	Twelve Months Ended June 30, 2013
UNS Energy	2.145	2.440
TEP	1.833	2.199

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.

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Environmental Matters

The table below provides a summary of the estimated impact of pending environmental regulations on TEP's annual O&M expense and capital expenditures.

Generating Station	Estimated  Annual O&M Expense		Estimated Capital Expenditures		Regulation (Compliance Date)	Upgrades
	Millions of Dollars
San Juan Unit 1	$	1	$	25	Regional Haze/BART (2016)	SNCRs(1)
Navajo Units 1-3	3		86		MATS (2015) Regional Haze/BART (2030)	Mercury Controls; SCRs; Baghouses
Four Corners Units 4 & 5	3		36		MATS (2015) Regional Haze/BART (2018)	Mercury Controls; SCRs
Springerville Units 1 & 2	3		5		MATS (2015)	Mercury Controls

⁽¹⁾ The current plan calls for the installation of SNCR technology on San Juan Unit 1 and the retirement of San Juan Unit 2. If SCR technology is installed on San Juan Units 1 and 2, TEP estimates its share of the cost would be $180 million to $200 million.

The table below provides TEP's ownership interest in coal-fired generating facilities.

	Unit	Net Capability	Operating	TEP's Share
Generating Facility	No.	MW	Agent	%	MW
Springerville Station(1)	1	401	TEP	100.0	401
Springerville Station	2	403	TEP	100.0	403
San Juan Station	1	340	PNM	50.0	170
San Juan Station	2	340	PNM	50.0	170
Navajo Station	1	750	SRP	7.5	56
Navajo Station	2	750	SRP	7.5	56
Navajo Station	3	750	SRP	7.5	56
Four Corners Station	4	784	APS	7.0	55
Four Corners Station	5	784	APS	7.0	55
Sundt Station(2)	4	120	TEP	100.0	120

⁽¹⁾ As of June 30, 2013, TEP owned a 14% undivided interest in Springerville Unit 1 and leased the remaining 86%.

⁽²⁾ Sundt Unit 4 is a dual fuel unit that can be operated with coal or natural gas. The net generating capability when Sundt Unit 4 is operated with with natural gas is 156 MW.

Greenhouse Gas Regulation

On June 25, 2013, President Obama directed the EPA to move forward with regulations to limit carbon emissions from new and existing fossil fueled power plants.  Specifically, the President directed the EPA to issue a re-proposed rule for new power plants by September 20, 2013. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

Additionally, the President ordered the EPA to:

• propose carbon emission standards for existing power plants by June 1, 2014;

• finalize those standards by June 1, 2015; and

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

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

For more information on TEP's environmental matters, please see Note 4.

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 30, 2013	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer
		TUCSON ELECTRIC POWER COMPANY
		(Registrant)
Date:	July 30, 2013	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer

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EXHIBIT INDEX

* 10(a)		Severance Agreement between Michael J. DeConcini and Tucson Electric Power Company. (Form 8-K dated July 25, 2013, File 1-13739 - Exhibit 10(a)).
* 10(b)		UNS Energy Corporation Severance Plan, as amended. (Form 8-K dated July 25, 2013, File 1-13739 - Exhibit 10(b)).
12(a)	—	Computation of Ratio of Earnings to Fixed Charges – UNS Energy.
12(b)	—	Computation of Ratio of Earnings to Fixed Charges – TEP.
15(a)	—	Letter regarding unaudited interim financial information – UNS Energy.
15(b)	—	Letter regarding unaudited interim financial information – TEP.
31(a)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Paul J. Bonavia.
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 Paul J. Bonavia.
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 Corporation’s and Tucson Electric Power Company’s Quarterly Report on Form 10-Q for the three and six-month periods ended June 30, 2013, formatted in XBRL (Extensible Business Reporting Language):

(a) UNS Energy Corporation’s and Tucson Electric Power Company’s (i) Condensed Consolidated Statements of Income (ii) Condensed Consolidated Statements of Comprehensive Income (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Balance Sheets, (v) Condensed Consolidated Statement of Changes in Stockholders’ Equity; and

(b) Notes to Condensed Consolidated Financial Statements.

* Previously filed as indicated and incorporated herein by reference.

** Not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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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,
	2013			2013		2012		2011		2010		2009		2008
	Thousands of Dollars
Fixed Charges:
Interest on Long-Term Debt	$	35,954		$	71,126	$	71,909	$	73,217	$	65,020	$	58,134	$	70,227
Other Interest (1)	(47		)	916		1,954		2,535		1,651		3,468		1,837
Interest on Capital Lease Obligations	13,554			31,902		36,593		44,874		52,540		53,682		57,272
Estimated Interest Portion of Rental Expense	311			656		691		926		240		345		188
Total Fixed Charges	$	49,772		$	104,600	$	111,147	$	121,552	$	119,451	$	115,629	$	129,524
Net Income	$	45,963		$	104,132	$	90,919	$	109,975	$	112,984	$	105,901	$	16,955
Add:
Losses from Equity Investees	—			7		7		—		5,570		1,834		713
Income Tax Expense	11,033			46,442		55,727		66,951		76,921		63,232		18,747
Total Fixed Charges	49,772			104,600		111,147		121,552		119,451		115,629		129,524
Total Earnings before Taxes and Fixed Charges	$	106,768		$	255,181	$	257,800	$	298,478	$	314,926	$	286,596	$	165,939
Ratio of Earnings to Fixed Charges	2.145			2.440		2.319		2.456		2.636		2.479		1.281

⁽¹⁾  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,
	2013			2013		2012		2011		2010		2009		2008
	Thousands of Dollars
Fixed Charges:
Interest on Long-Term Debt	$	28,564		$	56,308	$	55,038	$	49,858	$	42,378	$	36,226	$	47,456
Other Interest (1)	(168		)	502		1,446		1,127		433		1,571		1,367
Interest on Capital Lease Obligations	13,554			31,902		36,593		44,874		52,534		53,670		57,252
Estimated Interest Portion of Rental Expense	279			585		611		795		72		106		130
Total Fixed Charges	$	42,229		$	89,297	$	93,688	$	96,654	$	95,417	$	91,573	$	106,205
Net Income (Loss)	$	32,266		$	77,287	$	65,470	$	85,334	$	108,260	$	90,688	$	7,206
Add (Deduct):
(Income) from Equity Investees	—			—		—		—		—		—		(1,381		)
Income Tax Expense (Benefit)	2,909			29,745		39,109		52,000		59,936		54,220		12,729
Total Fixed Charges	42,229			89,297		93,688		96,654		95,417		91,573		106,205
Total Earnings before Taxes and Fixed Charges	$	77,404		$	196,329	$	198,267	$	233,988	$	263,613	$	236,481	$	124,759
Ratio of Earnings to Fixed Charges	1.833			2.199		2.116		2.421		2.763		2.582		1.175

⁽¹⁾  Excludes recognition of Allowance for Borrowed Funds Used During Construction.

EX-15.A

Exhibit 15(a)

July 30, 2013

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

Commissioners:

We are aware that our report dated July 30, 2013, on our review of condensed consolidated interim financial information of UNS Energy Corporation (the "Company") for the three-month and six-month periodsended June 30, 2013 and 2012 and included in the Company's quarterly report on Form 10-Q for the quarter ended June 30, 2013, is incorporated by reference in its Registration Statements on Form S-8 dated January 6, 1998 (No. 333-43765), January 6, 1998 (No. 333-43767), January 6, 1998 (No. 333-43769), May 21, 1998 (No. 333-53309), May 21, 1998 (No. 333-53333), September 9, 2002 (No. 333-99317), January 31, 2007 (No. 333-140353), December 30, 2008 (No. 333-156491), and June 17, 2011 (No. 333-175001) and on Form S-3 dated May 10, 2012 (No. 333-181305).

Very truly yours,

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

EX-15.B

Exhibit 15(b)

July 30, 2013

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

Commissioners:

We are aware that our report dated July 30, 2013, on our review of condensed consolidated interim financial information of Tucson Electric Power Company (the "Company") for the three-month and six-month periods ended June 30, 2013 and 2012 and included in the Company's quarterly report on Form 10-Q for the quarter ended June 30, 2013, is incorporated by reference in its Registration Statement on Form S-3 dated May 10, 2012 (No. 333-181305-01).

Very truly yours,

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

EX-31.A

Exhibit 31(a)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Paul J. Bonavia, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013, 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 30, 2013	/s/ Paul J. Bonavia
		Paul J. Bonavia
		Chairman 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, 2013, 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 30, 2013	/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, Paul J. Bonavia, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013, 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 30, 2013	/s/ Paul J. Bonavia
		Paul J. Bonavia
		Chairman 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, 2013, 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 30, 2013	/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, Paul J. Bonavia, Chairman of the Board and Chief Executive Officer of UNS Energy Corporation (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, 2013, 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 30, 2013

/s/ Paul J. Bonavia

Paul J. Bonavia

Chairman of the Board 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, Paul J. Bonavia, Chairman of the Board 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, 2013, 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 30, 2013

/s/ Paul J. Bonavia

Paul J. Bonavia

Chairman of the Board 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

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS

6 Months Ended

Jun. 30, 2013

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable. Level 3 inputs are unobservable and supported by little or no market activity.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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

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

• For Investment in Lease Debt, we calculate the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporate the impact of counterparty credit risk using market credit default swap data.

• 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, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		24		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,523		1,572		1,498		1,583
TEP	Level 2	1,224		1,245		1,223		1,271

TEP's Investment in Lease Debt matured in January 2013. This investment was stated at amortized cost, which means the purchase cost was adjusted for the amortization of the premium and discount to maturity.

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. There were no transfers between Levels 1, 2, or 3 for either reporting period.

	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, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	15		$	15	$	—		$	—		$	—		$	15
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	20			—		20			—			—			20
Energy Contracts - Regulatory Recovery(3)	5			—		2			3			(3		)	2
Total Assets	42			17		22			3			(3		)	39
Liabilities
Energy Contracts - Regulatory Recovery(3)	(12		)	—		(6		)	(6		)	3			(9		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(9		)	—		(9		)	—			—			(9		)
Total Liabilities	(23		)	—		(15		)	(8		)	3			(20		)
Net Total Assets (Liabilities)	$	19		$	17	$	7		$	(5	)	$	—		$	19

	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, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery(3)	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	20			—		20			—			—			20
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	25			2		21			2			(1		)	24
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(2		)	(1		)	1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(9		)	—		(9		)	—			—			(9		)
Total Liabilities	(14		)	—		(11		)	(3		)	1			(13		)
Net Total Assets (Liabilities)	$	11		$	2	$	10		$	(1	)	$	—		$	11

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1		$	1	$	—		$	—		$	—		$	1
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	30			8		20			2			(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(3		)	—			1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(15		)	—		(13		)	(2		)	1			(14		)
Net Total Assets (Liabilities)	$	15		$	8	$	7		$	—		$	—		$	15

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

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

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

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

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

DERIVATIVE INSTRUMENTS

Regulatory Recovery

We are exposed to energy price risk associated with our gas and purchased power requirements. We reduce our energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or Purchased Gas Adjustor (PGA). See Note 2.

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange pricing, adjusted for basis differences, 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 options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, correlations, interest rates, and forward price curves.

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

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

Cash Flow Hedges

We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. These swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. This swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 12. The amount expected to be reclassified to earnings within the next twelve months is estimated to be $4 million.

Financial Impact of Energy Contracts

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

	UNS Energy					TEP
	Three Months Ended June 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	9	$	(17	)	$	3	$	(6	)

	UNS Energy					TEP
	Six Months Ended June 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	—	$	(9	)	$	1	$	(1	)

Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At June 30, 2013, UNS Energy and TEP have energy contracts that will settle through the second quarter of 2016.

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	June 30, 2013	December 31, 2012	June 30, 2013	December 31, 2012
Power Contracts GWh	2,231	2,228	909	820
Gas Contracts GBtu	20,289	17,851	8,090	7,958

Level 3 Fair Value Measurements

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

		Fair Value at
		June 30, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	2	$	(8	)	Market price per MWh	$	24.00		-	$	53.25
Option Contracts(2)	Option model	1		—			Market Price per MWh	$	34.00		-	$	44.75
							Power Volatility	29.75		%	-	77.2		%
							Market Price per MMbtu	$	3.38		-	$	3.65
							Gas Volatility	29.69		%	-	32.37		%
Level 3 Energy Contracts		$	3	$	(8	)

⁽¹⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

⁽²⁾  All of the option contracts relate to TEP.

Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statement.

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

	Three Months Ended June 30, 2013
	UNS Energy			TEP
	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	)	$	—

	Six Months Ended June 30, 2013
	UNS Energy		TEP
	Millions of Dollars
Balances at December 31, 2012	(5	)	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(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	)

	Three Months Ended June 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at March 31, 2012	$	(13	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	2			(1		)
Settlements	4			—
Balances at June 30, 2012	$	(7	)	$	(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		$	—

	Six Months Ended June 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)	—
Settlements	7			(1		)
Balances at June 30, 2012	$	(7	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

CREDIT RISK

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. The impact of counterparty credit risk and our own credit risk on the fair value of derivative contracts was less than $0.1 million at June 30, 2013 and at December 31, 2012.

At June 30, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $30 million for UNS Energy and $13 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $30 million for UNS Energy and $13 million for TEP.

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UNS ENERGY EARNINGS PER SHARE - 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, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Numerator:
Net Income	$ 34,618		$ 26,273		$ 45,963		$ 32,749
Dilutive Securities, Effect on Basic Earnings Per Share	0	[1]	237	[1]	0	[1]	1,100	[1]
Undistributed Earnings, Diluted	$ 34,618		$ 26,510		$ 45,963		$ 33,849
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,427		40,322		41,404		39,107
Fully Vested Deferred Stock Units	171		149		165		144
Total Weighted Average Shares of Common Stock Outstanding and Participating Securities - Basic	41,598		40,471		41,569		39,251
Incremental Common Shares Attributable to Conversion of Debt Securities	0	[2]	909	[2]	0	[2]	2,125	[2]
Effect of Dilutive Securities:
Options and Stock Issuable Under Share-Based Compensation Plans	323		250		329		270
Total Shares - Diluted	41,921		41,630		41,898		41,646

[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] In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	$ 933	$ 280	$ 1,544	$ 272
Income Tax on Unrealized Gain (Loss) on Cash Flow Hedges	(610)	(184)	(1,009)	(177)
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	(43)	(34)	(85)	(15)
TUCSON ELECTRIC POWER COMPANY
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	878	389	1,456	427
Income Tax on Unrealized Gain (Loss) on Cash Flow Hedges	(574)	(255)	(952)	(279)
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	$ (43)	$ (34)	$ (85)	$ (15)

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REGULATORY MATTERS

6 Months Ended

Jun. 30, 2013

REGULATORY MATTERS

REGULATORY MATTERS

RATES AND REGULATION

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

2013 TEP RATE ORDER

In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

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

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

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

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

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

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

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

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

The 2013 TEP Rate Order also includes:

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

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

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

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

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

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

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

PENDING UNS ELECTRIC RATE CASE

In December 2012, as required in the 2010 UNS Electric Rate Order, UNS Electric filed with the ACC a general rate case, on a cost-of-service basis, requesting the following:

• a non-fuel Base Rate increase of $7.5 million, or 4.6%;

• an OCRB of approximately $217 million and a FVRB of $286 million;

• a return on equity of 10.5%, a long-term cost of debt of 5.97%;

• a capital structure of approximately 53% equity and 47% long-term debt; and

• a 1.6% return on the fair value increment of rate base. The fair value increment of rate base represents the difference between OCRB and FVRB of approximately $69 million.

UNS Electric also requested the following:

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

• a Transmission Cost Adjustor (TCA). The TCA would allow UNS Electric to recover, on a more timely basis, transmission costs associated with serving retail customers.

ACC Staff and other parties have filed testimony with recommendations ranging from no rate increase to a 0.8% rate increase.

REGULATORY ASSETS AND LIABILITIES

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

	June 30, 2013						December 31, 2012
	UNS Energy			TEP			UNS Energy			TEP
	Millions of Dollars
Regulatory Assets – Current	$	55		$	36		$	52		$	34
Regulatory Assets – Noncurrent (1)	204			190			191			178
Regulatory Liabilities—Current (2)	(54		)	(30		)	(44		)	(21		)
Regulatory Liabilities – Noncurrent (3)	(295		)	(256		)	(279		)	(241		)
Total Net Regulatory Assets (Liabilities)	$	(90	)	$	(60	)	$	(80	)	$	(50	)

⁽¹⁾  Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment, See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.

⁽²⁾  Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.

⁽³⁾  Regulatory Liabilities - Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF REGULATORY ACCOUNTING

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

• Reflecting regulatory pension assets as part of Accumulated Other Comprehensive Income (AOCI)

• Writing off the remaining regulatory assets as an expense and regulatory liabilities as income in the income statements

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

• TEP would have recorded an extraordinary after-tax gain of $112 million and an after-tax loss in AOCI of $76 million;

• UNS Gas would have recorded an extraordinary after-tax gain of $24 million and an after-tax loss in AOCI of $2 million; and

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

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

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REGULATORY MATTERS (Tables)

6 Months Ended

Jun. 30, 2013

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

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

	June 30, 2013						December 31, 2012
	UNS Energy			TEP			UNS Energy			TEP
	Millions of Dollars
Regulatory Assets – Current	$	55		$	36		$	52		$	34
Regulatory Assets – Noncurrent (1)	204			190			191			178
Regulatory Liabilities—Current (2)	(54		)	(30		)	(44		)	(21		)
Regulatory Liabilities – Noncurrent (3)	(295		)	(256		)	(279		)	(241		)
Total Net Regulatory Assets (Liabilities)	$	(90	)	$	(60	)	$	(80	)	$	(50	)

⁽¹⁾  Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment, See Note 6. This regulatory asset does not earn a return and will be recovered through future rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.

⁽²⁾  Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement.

⁽³⁾  Regulatory Liabilities - Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended.

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SUPPLEMENTAL CASH FLOW INFORMATION SUPPLEMENTAL CASH FLOW INFORMATION - Non-Cash Transactions (Details) (USD $) In Millions, unless otherwise specified			6 Months Ended
	Mar. 31, 2013 Unsecured Tax Exempt Bonds [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2012 Unsecured Tax Exempt Bonds [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2012 Convertible Senior Notes [Member] UNS Energy Corporation [Member]
Debt Instrument, Face Amount	$ 91	$ 193
Debt Conversion, Converted Instrument, Amount			147
Debt Conversion, Original Debt, Amount			$ 150

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UNS ENERGY EARNINGS PER SHARE

6 Months Ended

Jun. 30, 2013

UNS ENERGY EARNINGS PER SHARE

UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options, share-based compensation awards, or UNS Energy's Convertible Senior Notes were exercised or converted into Common Stock. We excluded anti-dilutive stock options from the calculation of diluted EPS. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the remaining notes, not yet converted, were converted to Common Stock.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	Thousands of Dollars
Numerator:
Net Income	$	34,618	$	26,273	$	45,963	$	32,749
Income from Assumed Conversion of Convertible Senior Notes (1)	—		237		—		1,100
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	34,618	$	26,510	$	45,963	$	33,849
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,427		40,322		41,404		39,107
Fully Vested Deferred Stock Units	171		149		165		144
Total Weighted Average Common Stock Outstanding – Basic	41,598		40,471		41,569		39,251
Effect of Dilutive Securities:
Convertible Senior Notes (1)	—		909		—		2,125
Options and Stock Issuable Under Share-Based Compensation Plans	323		250		329		270
Total Weighted Average Common Stock Outstanding – Diluted	41,921		41,630		41,898		41,646

⁽¹⁾ In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

We excluded the following outstanding stock options, with an exercise price above market, from our diluted EPS computation as their effect would be anti-dilutive:

	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
	Thousands of Shares
Stock Options	—	101	—	101

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Financial Impact of Energy Contracts (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Increase (Decrease) to Regulatory Assets/Liabilities	$ 9	$ (17)	$ 0	$ (9)
TUCSON ELECTRIC POWER COMPANY
Derivative Instruments, Gain (Loss) [Line Items]
Increase (Decrease) to Regulatory Assets/Liabilities	$ 3	$ (6)	$ 1	$ (1)

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT CHANGES IN ACCUMULATIVE OTHER COMPREHENSIVE INCOME BY COMPONENT (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Amortization of SERP and Defined Benefit Plans
Tax (Expense) Benefit	$ 43,000	$ 34,000	$ 85,000	$ 15,000
Amortization, Net of Taxes	(68,000)	(55,000)	(137,000)	(163,000)
TUCSON ELECTRIC POWER COMPANY
Gains and Losses on Cash Flow Hedges
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	400,000		800,000
Net of Tax	(659,000)		(1,193,000)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(111,000)		(222,000)
Tax (Expense) Benefit	43,000	34,000	85,000	15,000
Amortization, Net of Taxes	(68,000)	(55,000)	(137,000)	(163,000)
Total Reclassification from Other Comprehensive Income for the Period	(700,000)		(1,300,000)
UNS Energy Corporation [Member]
Gains and Losses on Cash Flow Hedges
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	500,000		800,000
Net of Tax	(690,000)		(1,255,000)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(111,000)		(222,000)
Tax (Expense) Benefit	43,000		100,000
Amortization, Net of Taxes	(68,000)		(137,000)
Total Reclassification from Other Comprehensive Income for the Period	(800,000)		(1,400,000)
Interest Rate Contract Long Term Debt [Member] | TUCSON ELECTRIC POWER COMPANY
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	293,000		575,000
Interest Rate Contract Long Term Debt [Member] | UNS Energy Corporation [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	346,000		676,000
Interest Rate contract Capital Leases [Member] | TUCSON ELECTRIC POWER COMPANY
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	604,000		1,208,000
Interest Rate contract Capital Leases [Member] | UNS Energy Corporation [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	604,000		1,208,000
Commodity Contract [Member] | TUCSON ELECTRIC POWER COMPANY
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	191,000		191,000
Commodity Contract [Member] | UNS Energy Corporation [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	$ 191,000		$ 191,000

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INCOME TAXES - Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate (Detail) (USD $)	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Income Taxes [Line Items]
Statutory tax rate				35.00%
Federal Income Tax Expense at Statutory Rate		$ 14,000,000	$ 15,000,000	$ 20,000,000	$ 19,000,000
State Income Tax Expense, Net of Federal Deduction		2,000,000	2,000,000	3,000,000	2,000,000
Cash Surrender Value of Life Insurance				0	(1,000,000)
Investment Tax Credit Basis Difference	(11,000,000)	(11,000,000)	0	(11,039,000)	0
Other		(1,000,000)	0	(1,000,000)	0
Income Tax Expense (Benefit)		3,675,000	17,111,000	11,033,000	20,319,000
TUCSON ELECTRIC POWER COMPANY
Income Taxes [Line Items]
Federal Income Tax Expense at Statutory Rate		12,000,000	13,000,000	12,000,000	11,000,000
State Income Tax Expense, Net of Federal Deduction		2,000,000	1,000,000	2,000,000	2,000,000
Cash Surrender Value of Life Insurance				0	(1,000,000)
Investment Tax Credit Basis Difference	(11,000,000)	(11,000,000)	0	(10,751,000)	0
Other		(1,000,000)	0	0	0
Income Tax Expense (Benefit)		$ 1,652,000	$ 14,242,000	$ 2,909,000	$ 12,273,000

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EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 30, 2013

Components of Net Periodic Benefit Cost

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

	Pension Benefits						Other Retiree Benefits
	Three Months Ended June 30,
	2013			2012			2013		2012
	Millions of Dollars
Service Cost	$	3		$	2		$	1	$	1
Interest Cost	4			4			1		1
Expected Return on Plan Assets	(5		)	(4		)	—		—
Actuarial Loss Amortization	2			2			—		—
Net Periodic Benefit Cost	$	4		$	4		$	2	$	2

	Pension Benefits						Other Retiree Benefits
	Six Months Ended June 30,
	2013			2012			2013		2012
	Millions of Dollars
Service Cost	$	6		$	5		$	2	$	1
Interest Cost	8			8			1		2
Expected Return on Plan Assets	(10		)	(9		)	—		—
Actuarial Loss Amortization	4			4			—		—
Net Periodic Benefit Cost	$	8		$	8		$	3	$	3

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INCOME TAXES (Tables)

6 Months Ended

Jun. 30, 2013

Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate

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

	UNS Energy					TEP
	Three Months Ended June 30,
	2013			2012		2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	14		$	15	$	12		$	13
State Income Tax Expense, Net of Federal Deduction	2			2		2			1
Investment Tax Credit Basis Difference	(11		)	—		(11		)	—
Other	(1		)	—		(1		)	—
Total Federal and State Income Tax Expense	$	4		$	17	$	2		$	14

	UNS Energy						TEP
	Six Months Ended June 30,
	2013			2012			2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	20		$	19		$	12		$	11
State Income Tax Expense, Net of Federal Deduction	3			2			2			2
Cash Surrender Value of Life Insurance	—			(1		)	—			(1		)
Investment Tax Credit Basis Difference	(11		)	—			(11		)	—
Other	(1		)	—			—			—
Total Federal and State Income Tax Expense	$	11		$	20		$	3		$	12

Summary of Income Tax Contingencies

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	UNS Energy			TEP
	Millions of Dollars
Unrecognized Tax Benefits at December 31, 2012	$	30		$	23
Additions Based on Tax Positions Taken in the Current Year	1			1
Reduction of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(22		)
Unrecognized Tax Benefits at June 30, 2013	$	3		$	2

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Schedule of Fair Value Measurements of Financial Assets and Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013		Dec. 31, 2012
Assets
Cash Equivalent	$ 15	[1]	$ 20	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	20	[2]	19	[2]
Energy Contracts	5	[3]	7	[3]
Total Assets	42		53
Liabilities
Total Liabilities	(23)		(27)
Net Total Assets and (Liabilities)	19		26
Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	12	[3]	15	[3]
Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[4]	10	[4]
TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	1	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	20	[2]	19	[2]
Energy Contracts	3	[3]	3	[3]
Total Assets	25		30
Liabilities
Total Liabilities	(14)		(15)
Net Total Assets and (Liabilities)	11		15
TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	3	[3]	3	[3]
TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[4]	10	[4]
Level 1 [Member]
Assets
Cash Equivalent	15	[1]	20	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	0	[3]
Total Assets	17		27
Liabilities
Total Liabilities	0		0
Net Total Assets and (Liabilities)	17		27
Level 1 [Member] | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	1	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	0	[3]
Total Assets	2		8
Liabilities
Total Liabilities	0		0
Net Total Assets and (Liabilities)	2		8
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Level 2 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	20	[2]	19	[2]
Energy Contracts	2	[3]	2	[3]
Total Assets	22		21
Liabilities
Total Liabilities	(15)		(17)
Net Total Assets and (Liabilities)	7		4
Level 2 [Member] | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6	[3]	7	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[4]	10	[4]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	20	[2]	19	[2]
Energy Contracts	1	[3]	1	[3]
Total Assets	21		20
Liabilities
Total Liabilities	(11)		(13)
Net Total Assets and (Liabilities)	10		7
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	3	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[4]	10	[4]
Level 3 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	3	[3]	5	[3]
Total Assets	3		5
Liabilities
Total Liabilities	(8)		(10)
Net Total Assets and (Liabilities)	(5)		(5)
Level 3 [Member] | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6	[3]	8	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Level 3 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash(1)	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	2	[3]	2	[3]
Total Assets	2		2
Liabilities
Total Liabilities	(3)		(2)
Net Total Assets and (Liabilities)	(1)		0
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1	[3]	0	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4]	0	[4]
Netting [Member]
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash(1)	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	(3)	[3],[5]	(5)	[3],[5]
Total Assets	(3)	[5]	(5)	[5]
Liabilities
Total Liabilities	3	[5]	5	[5]
Net Total Assets and (Liabilities)	0	[5]	0	[5]
Netting [Member] | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	(3)	[3],[5]	(5)	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4],[5]	0	[4],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash(1)	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	(1)	[3],[5]	(1)	[3],[5]
Total Assets	(1)	[5]	(1)	[5]
Liabilities
Total Liabilities	1	[5]	1	[5]
Net Total Assets and (Liabilities)	0	[5]	0	[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	(1)	[3],[5]	(1)	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[3],[5]	0	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	[4],[5]	0	[4],[5]
Net Fair Value [Member]
Assets
Cash Equivalent	15	[1]	20	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	20	[2]	19	[2]
Energy Contracts	2	[3]	2	[3]
Total Assets	39		48
Liabilities
Total Liabilities	(20)		(22)
Net Total Assets and (Liabilities)	19		26
Net Fair Value [Member] | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[3]	10	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9	[4]	10	[4]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	1	[1]
Restricted Cash(1)	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	20	[2]	19	[2]
Energy Contracts	2	[3]	2	[3]
Total Assets	24		29
Liabilities
Total Liabilities	(13)		(14)
Net Total Assets and (Liabilities)	11		15
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2	[3]	2	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 9	[4]	$ 10	[4]

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

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

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

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

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

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REGULATORY MATTERS - Regulatory Assets and Liabilities (Detail) (USD $)	Jun. 30, 2013		Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets—Current	$ 54,782,000		$ 51,619,000
Regulatory Assets—Noncurrent	204,034,000	[1]	191,077,000	[1]
Regulatory Liabilities - Current	(54,030,000)	[2]	(43,516,000)	[2]
Regulatory Liabilities - Noncurrent	(294,950,000)	[3]	(279,111,000)	[3]
Total Net Regulatory Assets (Liabilities)	(90,000,000)		(80,000,000)
TUCSON ELECTRIC POWER COMPANY
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets—Current	36,283,000		34,345,000	[1]
Regulatory Assets—Noncurrent	190,488,000	[1]	178,330,000	[1]
Regulatory Liabilities - Current	(29,562,000)	[2]	(20,822,000)	[2]
Regulatory Liabilities - Noncurrent	(256,292,000)	[3]	(241,189,000)	[3]
Total Net Regulatory Assets (Liabilities)	$ (60,000,000)		$ (50,000,000)

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

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

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

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS - TEP and UNS Commitments (Detail) (USD $) In Millions, unless otherwise specified				1 Months Ended
	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY Purchased Power [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY Renewable Energy Power Purchase Agreement [Member]	Jun. 30, 2013 Uns Gas Incorporated [Member] Fuel [Member]	Jun. 30, 2013 UNS ELECTRIC, INC. [Member]	Dec. 31, 2012 UNS ELECTRIC, INC. [Member]	Jun. 30, 2013 UNS ELECTRIC, INC. [Member] Purchased Power [Member]	Jun. 30, 2013 Minimum [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Minimum [Member] UNS ELECTRIC, INC. [Member]	Jun. 30, 2013 Maximum [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Maximum [Member] UNS ELECTRIC, INC. [Member]
Commitments And Contingencies [Line Items]
Company Share Of Reclamation Costs At Expiration Dates Of Coal Supply Agreements	$ 27
Mine Reclamation and Closing Liability, Noncurrent	17	16
Unrecorded Unconditional Purchase Obligation, Due after Five Years				56
Increase (Decrease) Renewable Energy Standard Total Performance-Based Incentives Obligation	4					1
Future Maturities Of Renewable Energy Standard Performance-Based Incentives Obligation									9 years	10 years	20 years	20 years
Renewable Energy Standard Total Performance-Based Incentives Obligation	66	62				7	6
Unrecorded Unconditional Purchase Obligation, Due within Four Years				4	1
Unrecorded Unconditional Purchase Obligation, Due within Two Years			9	4	3			4
Duration of Power Purchase Agreement, In Years				20 years
Output Purchase Requirement From Renewable Energy Facility				100.00%
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months				4
Unrecorded Unconditional Purchase Obligation, Due within Three Years				4	2			3
Unrecorded Unconditional Purchase Obligation, Due within Five Years				$ 4

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Derivative Volumes (Details)	Jun. 30, 2013 GWh	Dec. 31, 2012 GWh
Power Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gas Swaps	2,231	2,228
Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gas Swaps	20,289	17,851
TUCSON ELECTRIC POWER COMPANY | Power Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gas Swaps	909	820
TUCSON ELECTRIC POWER COMPANY | Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gas Swaps	8,090	7,958

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT CHANGES IN ACCUMULATIVE OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)

6 Months Ended

Jun. 30, 2013

Statement of Other Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The realized changes in accumulated other comprehensive income by component are as follows:

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Three Months Ended June 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(346	)	$	(293	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(604		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(191		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	451			429
Realized Losses on Cash Flow Hedges, Net of Taxes	(690		)	(659		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(111		)	(111		)	Other Expense
Tax Benefit	43			43
Amortization, Net of Taxes	(68		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(758	)	$	(727	)

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Six Months Ended June 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(676	)	$	(575	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,208		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(191		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	820			781
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,255		)	(1,193		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(222		)	(222		)	Other Expense
Tax Benefit	85			85
Amortization, Net of Taxes	(137		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,392	)	$	(1,330	)

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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, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 3	$ 2	$ 6	$ 5
Interest Cost	4	4	8	8
Expected Return on Plan Assets	(5)	(4)	(10)	(9)
Amortization of Net Loss	2	2	4	4
Net Periodic Benefit Plan Cost	4	4	8	8
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1	2	1
Interest Cost	1	1	1	2
Expected Return on Plan Assets	0	0	0	0
Amortization of Net Loss	0	0	0	0
Net Periodic Benefit Plan Cost	$ 2	$ 2	$ 3	$ 3

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BUSINESS SEGMENTS (Tables)

6 Months Ended

Jun. 30, 2013

Reconciling Adjustments of Income Statement Items in Consolidation

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

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Three Months Ended June 30, 2013
Operating Revenues – External	$	300	$	21	$	44	$	—	$	—		$	365
Operating Revenues – Intersegment(1)	4		1		—		4		(9		)	—
Net Income	31		—		4		—		—			35
Three Months Ended June 30, 2012
Operating Revenues – External	$	295	$	21	$	48	$	—	$	—		$	364
Operating Revenues – Intersegment(1)	4		1		—		5		(10		)	—
Net Income	22		—		4		—		—			26

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Six Months Ended June 30, 2013
Operating Revenues – External	$	543	$	73	$	80	$	1	$	—		$	697
Operating Revenues – Intersegment(1)	9		1		1		8		(19		)	—
Net Income	32		8		6		—		—			46
Six Months Ended June 30, 2012
Operating Revenues – External	$	515	$	73	$	91	$	—	$	—		$	679
Operating Revenues – Intersegment(1)	8		2		1		9		(20		)	—
Net Income	20		5		7		1		—			33

⁽¹⁾  Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013		Dec. 31, 2012
Utility Plant
Plant in Service	$ 5,080,381		$ 5,005,768
Utility Plant Under Capital Leases	582,669		582,669
Construction Work in Progress	170,436		128,621
Total Utility Plant	5,833,486		5,717,058
Less Accumulated Depreciation and Amortization	(1,961,489)		(1,921,733)
Less Accumulated Amortization of Capital Lease Assets	(504,607)		(494,962)
Total Utility Plant—Net	3,367,390		3,300,363
Investments And Other Property
Investments in Lease Equity	36,266		36,339
Other	32,736		36,537
Total Investments and Other Property	69,002		72,876
Current Assets
Cash and Cash Equivalents	69,693		123,918
Accounts Receivable—Customer	109,022		93,742
Unbilled Accounts Receivable	63,285		53,568
Allowance for Doubtful Accounts	(6,861)		(6,545)
Materials and Supplies	107,795		93,322
Fuel Inventory	52,166		62,019
Deferred Income Taxes—Current	41,263		34,260
Regulatory Assets—Current	54,782		51,619
Investments in Lease Debt	0		9,118
Derivative Instruments	2,961		3,165
Other	15,526		33,567
Total Current Assets	509,632		551,753
Regulatory and Other Assets
Regulatory Assets—Noncurrent	204,034	[1]	191,077	[1]
Other Assets	26,322		24,360
Total Regulatory and Other Assets	230,356		215,437
Total Assets	4,176,380		4,140,429
Capitalization
Common Stock Equity	1,078,420		1,065,465
Capital Lease Obligations	176,144		262,138
Long-Term Debt	1,522,504		1,498,442
Total Capitalization	2,777,068		2,826,045
Current Liabilities
Current Obligations Under Capital Leases	100,380		90,583
Borrowings Under Revolving Credit Facilities	42,000		0
Accounts Payable—Trade	98,591		107,740
Accrued Taxes Other than Income Taxes	42,429		41,939
Interest Accrued	17,055		31,950
Accrued Employee Expenses	21,573		24,094
Regulatory Liabilities—Current	54,030	[2]	43,516	[2]
Customer Deposits	35,479		34,048
Derivative Instruments	13,929		14,742
Other	15,776		10,517
Total Current Liabilities	441,242		399,129
Liabilities, Noncurrent [Abstract]
Deferred Tax Liabilities, Net, Noncurrent	415,334		364,756
Regulatory Liability, Noncurrent	294,950	[3]	279,111	[3]
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	157,276		159,401
Derivative Liabilities, Noncurrent	9,277		12,709
Other Liabilities, Noncurrent	81,233		99,278
Liabilities, Noncurrent	958,070		915,255
Commitments and Contingencies
Total Capitalization and Other Liabilities	4,176,380		4,140,429
TUCSON ELECTRIC POWER COMPANY
Utility Plant
Plant in Service	4,407,267		4,348,041
Utility Plant Under Capital Leases	582,669		582,669
Construction Work in Progress	123,693		98,460
Total Utility Plant	5,113,629		5,029,170
Less Accumulated Depreciation and Amortization	(1,812,994)		(1,783,787)
Less Accumulated Amortization of Capital Lease Assets	(504,607)		(494,962)
Total Utility Plant—Net	2,796,028		2,750,421
Investments And Other Property
Investments in Lease Equity	36,266		36,339
Other	31,295		35,091
Total Investments and Other Property	67,561		71,430
Current Assets
Cash and Cash Equivalents	28,117		79,743
Accounts Receivable—Customer	89,172		71,813
Unbilled Accounts Receivable	52,420		33,782
Allowance for Doubtful Accounts	(4,913)		(4,598)
Accounts Receivable, Related Parties, Current	3,018		5,720
Materials and Supplies	94,717		80,377
Fuel Inventory	51,871		61,737
Deferred Income Taxes—Current	45,185		37,212
Regulatory Assets—Current	36,283		34,345	[1]
Investments in Lease Debt	0		9,118
Other	15,571		34,393
Total Current Assets	411,441		443,642
Regulatory and Other Assets
Regulatory Assets—Noncurrent	190,488	[1]	178,330	[1]
Other Assets	19,633		17,223
Total Regulatory and Other Assets	210,121		195,553
Total Assets	3,485,151		3,461,046
Capitalization
Common Stock Equity	894,786		860,927
Capital Lease Obligations	176,144		262,138
Long-Term Debt	1,223,505		1,223,442
Total Capitalization	2,294,435		2,346,507
Current Liabilities
Current Obligations Under Capital Leases	100,380		90,583
Borrowings Under Revolving Credit Facilities	30,000		0
Accounts Payable—Trade	81,406		82,122
Accounts Payable—Due to Affiliates	2,924		3,134
Accrued Taxes Other than Income Taxes	35,355		33,060
Interest Accrued	12,069		26,965
Accrued Employee Expenses	18,161		20,715
Regulatory Liabilities—Current	29,562	[2]	20,822	[2]
Customer Deposits	26,174		24,846
Derivative Instruments	6,959		4,899
Other	11,247		7,085
Total Current Liabilities	354,237		314,231
Liabilities, Noncurrent [Abstract]
Deferred Tax Liabilities, Net, Noncurrent	357,202		319,216
Regulatory Liability, Noncurrent	256,292	[3]	241,189	[3]
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	147,152		149,718
Derivative Liabilities, Noncurrent	7,197		10,565
Other Liabilities, Noncurrent	68,636		79,620
Liabilities, Noncurrent	836,479		800,308
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 3,485,151		$ 3,461,046

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

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

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

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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	6 Months Ended	3 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY
Common Stock, Shares Authorized	75,000,000
Tax effect of Other Comprehensive Income	$ (1,094)	$ (1,037)

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BUSINESS SEGMENTS

6 Months Ended

Jun. 30, 2013

BUSINESS SEGMENTS

BUSINESS SEGMENTS

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

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

(2) UNS Gas, a regulated gas distribution utility

(3) UNS Electric, a regulated electric utility

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

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Three Months Ended June 30, 2013
Operating Revenues – External	$	300	$	21	$	44	$	—	$	—		$	365
Operating Revenues – Intersegment(1)	4		1		—		4		(9		)	—
Net Income	31		—		4		—		—			35
Three Months Ended June 30, 2012
Operating Revenues – External	$	295	$	21	$	48	$	—	$	—		$	364
Operating Revenues – Intersegment(1)	4		1		—		5		(10		)	—
Net Income	22		—		4		—		—			26

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Six Months Ended June 30, 2013
Operating Revenues – External	$	543	$	73	$	80	$	1	$	—		$	697
Operating Revenues – Intersegment(1)	9		1		1		8		(19		)	—
Net Income	32		8		6		—		—			46
Six Months Ended June 30, 2012
Operating Revenues – External	$	515	$	73	$	91	$	—	$	—		$	679
Operating Revenues – Intersegment(1)	8		2		1		9		(20		)	—
Net Income	20		5		7		1		—			33

⁽¹⁾  Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

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FINANCIAL STATEMENT PRESENTATION

6 Months Ended

Jun. 30, 2013

NATURE OF OPERATIONS AND BASIS OF ACCOUNTING PRESENTATION

FINANCIAL STATEMENT PRESENTATION

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

We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2012 Annual Report on Form 10-K.

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

REVISION OF PRIOR PERIOD UNS ENERGY INCOME STATEMENT

During the first three quarters of 2012, we incorrectly reported UNS Electric's sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $3 million for the three months ended and $7 million for the six months endedJune 30, 2012. This error had no impact on operating income, net income, retained earnings, or cash flows.

We assessed the impact of this error on prior period financial statements and concluded it was not material to any period. However, this error was significant to individual income statement line items. As a result, in accordance with GAAP, we revised our prior period income statement as follows:

	UNS Energy
	Three Months Ended				Six Months Ended
	June 30, 2012				June 30, 2012
	As Reported		As Revised		As Reported		As Revised
	Thousands of Dollars				Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	28,684	$	25,511	$	65,787	$	59,127
Purchased Energy	51,376		48,203		114,653		107,993
Total Fuel and Purchased Energy	151,328		148,155		285,605		278,945
Total Operating Expenses	299,112		295,939		583,590		576,930

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2013, we adopted authoritative guidance that:

• Requires additional disclosures for amounts reclassified out of accumulated other comprehensive income by component. See Note 12.

• Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 11.

• Allows an additional option for impairment testing of indefinite-lived intangible assets. We had no impairment indicator as our only indefinite-lived intangible assets, Renewable Energy Credits (RECs), are currently recoverable under the Renewable Energy Standard (RES) as we use the RECs to comply with the standard’s renewable resources requirements.

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS - TEP Contingencies (Detail) (USD $) In Millions, unless otherwise specified		1 Months Ended					1 Months Ended
	Jun. 30, 2013 Tucson to Nogales [Member] mi	Mar. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY San Juan [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY Four Corner [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY Tucson to Nogales [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY Springerville [Member]	Jul. 31, 2013 TUCSON ELECTRIC POWER COMPANY Navajo [Member]	Jun. 30, 2013 UNS ELECTRIC, INC. [Member] Tucson to Nogales [Member]
Commitments And Contingencies [Line Items]
Better Than BART Agreement Year by which to Shut Down One Unit							2020
Percentage of ownership in generating station			20.00%	7.00%
Percentage of Ownership in Generating Units 1 & 2			50.00%
Estimated Loss Accrual Related to Four Corners Generating Station				$ 1
Transmission line from Tucson to Nogales	60
Transmission Line, in KV	345
Regulatory Assets					5.0			0.2
Lease Renewal Period						3 years
Lease Arrangement, Fair Market Value Purchase Price						159
Percentage Of Interest Not Owned						86.00%
Payment as a Result of Power Outage		$ 2
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

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2013

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, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		24		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,523		1,572		1,498		1,583
TEP	Level 2	1,224		1,245		1,223		1,271

Schedule of Fair Value Measurements of Financial Assets and Liabilities

There were no transfers between Levels 1, 2, or 3 for either reporting period.

	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, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	15		$	15	$	—		$	—		$	—		$	15
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	20			—		20			—			—			20
Energy Contracts - Regulatory Recovery(3)	5			—		2			3			(3		)	2
Total Assets	42			17		22			3			(3		)	39
Liabilities
Energy Contracts - Regulatory Recovery(3)	(12		)	—		(6		)	(6		)	3			(9		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(9		)	—		(9		)	—			—			(9		)
Total Liabilities	(23		)	—		(15		)	(8		)	3			(20		)
Net Total Assets (Liabilities)	$	19		$	17	$	7		$	(5	)	$	—		$	19

	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, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery(3)	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	June 30, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	20			—		20			—			—			20
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	25			2		21			2			(1		)	24
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(2		)	(1		)	1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(9		)	—		(9		)	—			—			(9		)
Total Liabilities	(14		)	—		(11		)	(3		)	1			(13		)
Net Total Assets (Liabilities)	$	11		$	2	$	10		$	(1	)	$	—		$	11

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1		$	1	$	—		$	—		$	—		$	1
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	30			8		20			2			(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(3		)	—			1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(15		)	—		(13		)	(2		)	1			(14		)
Net Total Assets (Liabilities)	$	15		$	8	$	7		$	—		$	—		$	15

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

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

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

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

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements. 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 [Table Text Block]

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

	UNS Energy					TEP
	Three Months Ended June 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	9	$	(17	)	$	3	$	(6	)

	UNS Energy					TEP
	Six Months Ended June 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	—	$	(9	)	$	1	$	(1	)

Derivative Volumes [Table Text Block]

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	June 30, 2013	December 31, 2012	June 30, 2013	December 31, 2012
Power Contracts GWh	2,231	2,228	909	820
Gas Contracts GBtu	20,289	17,851	8,090	7,958

Quantitative Information Regarding Unobservable Inputs

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

		Fair Value at
		June 30, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	2	$	(8	)	Market price per MWh	$	24.00		-	$	53.25
Option Contracts(2)	Option model	1		—			Market Price per MWh	$	34.00		-	$	44.75
							Power Volatility	29.75		%	-	77.2		%
							Market Price per MMbtu	$	3.38		-	$	3.65
							Gas Volatility	29.69		%	-	32.37		%
Level 3 Energy Contracts		$	3	$	(8	)

⁽¹⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

⁽²⁾  All of the option contracts relate to TEP.

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

.

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

	Three Months Ended June 30, 2013
	UNS Energy			TEP
	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	)	$	—

	Six Months Ended June 30, 2013
	UNS Energy		TEP
	Millions of Dollars
Balances at December 31, 2012	(5	)	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(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	)

	Three Months Ended June 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at March 31, 2012	$	(13	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	2			(1		)
Settlements	4			—
Balances at June 30, 2012	$	(7	)	$	(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		$	—

	Six Months Ended June 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)	—
Settlements	7			(1		)
Balances at June 30, 2012	$	(7	)	$	(1	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

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FINANCIAL STATEMENT PRESENTATION - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount		$ 3,000,000		$ 7,000,000
Electric Wholesale Sales	30,654,000	25,511,000	65,052,000	59,127,000
Utilities Operating Expense, Purchased Power	57,796,000	48,203,000	121,955,000	107,993,000
Total Fuel and Purchased Energy	150,850,000	148,155,000	294,516,000	278,945,000
Total Operating Expenses	304,414,000	295,939,000	596,660,000	576,930,000
Scenario, Previously Reported [Member]
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Electric Wholesale Sales		28,684,000		65,787,000
Utilities Operating Expense, Purchased Power		51,376,000		114,653,000
Total Fuel and Purchased Energy		151,328,000		285,605,000
Total Operating Expenses		$ 299,112,000		$ 583,590,000

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DEBT AND CREDIT FACILITIES (Detail) (USD $) In Millions, unless otherwise specified			1 Months Ended
	Mar. 31, 2013 TUCSON ELECTRIC POWER COMPANY Unsecured Tax Exempt Bonds [Member]	Jun. 30, 2012 TUCSON ELECTRIC POWER COMPANY Unsecured Tax Exempt Bonds [Member]	Mar. 31, 2013 TUCSON ELECTRIC POWER COMPANY Unsecured Tax Exempt Bonds Redemption [Member]	Jun. 30, 2013 Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Margin before Credit Rating Upgrade [Member] Revolving Credit Facility [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Margin before Credit Rating Upgrade [Member] Revolving Credit Facility [Member] UNS Energy Corporation [Member]	Jun. 30, 2013 Margin before Credit Rating Upgrade [Member] Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Margin before Credit Rating Upgrade [Member] 2010 TEP Reimbursement Agreement [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Margin After Credit Rating Upgrade [Member] Revolving Credit Facility [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Margin After Credit Rating Upgrade [Member] Revolving Credit Facility [Member] UNS Energy Corporation [Member]	Jun. 30, 2013 Margin After Credit Rating Upgrade [Member] Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 Margin After Credit Rating Upgrade [Member] 2010 TEP Reimbursement Agreement [Member] TUCSON ELECTRIC POWER COMPANY
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 91	$ 193	$ 91
Fixed interest rate of long-term debt	4.00%		6.375%
Debt Instrument, Increase, Accrued Interest			0.5
Capitalized value related to issuance of Bonds	1
Debt Instrument, Basis Spread on Variable Rate					1.125%	1.75%	1.125%	1.50%	1.00%	1.50%	1.00%	1.25%
Line of Credit Facility, Amount Outstanding				$ 186

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SUPPLEMENTAL CASH FLOW INFORMATION - Reconciliation of Net Income to Net Cash Flows from Operating Activities (Detail) (USD $) In Thousands, unless otherwise specified	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Supplemental Cash Flow Information [Line Items]
Net Income		$ 34,618	$ 26,273	$ 45,963	$ 32,749
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities
Depreciation Expense				72,970	70,174
Amortization Expense				16,408	17,776
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense				3,516	3,234
Amortization of Deferred Debt-Related Costs Included in Interest Expense				1,515	1,545
Provision for Retail Customer Bad Debts				936	1,571
Use of RECs for Compliance				8,106	3,055
Deferred Income Taxes				36,644	17,397
Investment Tax Credit Basis Adjustment	(11,000)	(11,000)	0	(11,039)	0
Pension and Postretirement Expense				11,391	10,927
Pension and Postretirement Funding				(8,924)	(10,957)
Share-Based Compensation Expense				1,390	1,170
Allowance for Equity Funds Used During Construction				(2,463)	(1,920)
Increase (Decrease) to Reflect PPFAC Recovery				(3,294)	11,654
PPFAC Reduction - TEP Rate Order				3,000	0
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately
Accounts Receivable				(20,706)	(19,547)
Materials and Fuel Inventory				8,777	(21,597)
Accounts Payable				(9,576)	(2,594)
Income Taxes				(15,980)	2,062
Interest Accrued				(6,885)	(7,839)
Taxes Other Than Income Taxes				490	952
Other				15,413	2,732
Net Cash Provided by (Used in) Operating Activities				147,652	112,544
TUCSON ELECTRIC POWER COMPANY
Supplemental Cash Flow Information [Line Items]
Net Income		30,787	21,910	32,266	20,449
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities
Depreciation Expense				57,418	55,012
Amortization Expense				18,275	19,620
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense				2,987	2,506
Amortization of Deferred Debt-Related Costs Included in Interest Expense				1,216	1,072
Provision for Retail Customer Bad Debts				711	1,104
Use of RECs for Compliance				7,414	2,622
Deferred Income Taxes				24,883	10,810
Investment Tax Credit Basis Adjustment	(11,000)	(11,000)	0	(10,751)	0
Pension and Postretirement Expense				9,939	9,644
Pension and Postretirement Funding				(8,493)	(9,856)
Share-Based Compensation Expense				1,108	923
Allowance for Equity Funds Used During Construction				(1,763)	(1,646)
Increase (Decrease) to Reflect PPFAC Recovery				2,914	5,125
PPFAC Reduction - TEP Rate Order	3,000			3,000	0
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately
Accounts Receivable				(30,452)	(34,287)
Materials and Fuel Inventory				8,923	(21,189)
Accounts Payable				(11)	7,686
Income Taxes				(10,798)	1,769
Interest Accrued				(6,886)	(6,805)
Taxes Other Than Income Taxes				2,295	3,454
Other				11,347	(1,507)
Net Cash Provided by (Used in) Operating Activities				$ 115,542	$ 66,506

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Quantitative Information Regarding Unobservable Inputs (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013		Dec. 31, 2012
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	$ 5	[1]	$ 7	[1]
Assets, Fair Value Disclosure	42		53
Liabilities, Fair Value Disclosure	23		27
Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	3	[1]	5	[1]
Assets, Fair Value Disclosure	3		5
Liabilities, Fair Value Disclosure	8		10
Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	2	[2]
Liabilities, Fair Value Disclosure	8	[2]
Level 3 [Member] | Valuation Technique: Option model [Member] | Options Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	(1)	[3]
Liabilities, Fair Value Disclosure	0	[3]
Unobservable Inputs: Market Price per MMBtu	3.38
Minimum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Unobservable Inputs: Market Price Per MWh	24.00
Minimum [Member] | Level 3 [Member] | Valuation Technique: Option model [Member] | Options Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Unobservable Inputs: Market Price Per MWh	34.00
Unobservable Inputs: Power Volatility	29.75%
Unobservable Inputs: Gas Volatility	29.69%
Maximum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Unobservable Inputs: Market Price Per MWh	53.25
Maximum [Member] | Level 3 [Member] | Valuation Technique: Option model [Member] | Options Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Unobservable Inputs: Market Price Per MWh	44.75
Unobservable Inputs: Power Volatility	77.20%
Unobservable Inputs: Market Price per MMBtu	3.65
Unobservable Inputs: Gas Volatility	32.37%
TUCSON ELECTRIC POWER COMPANY
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	3	[1]	3	[1]
Assets, Fair Value Disclosure	25		30
Liabilities, Fair Value Disclosure	14		15
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	2	[1]	2	[1]
Assets, Fair Value Disclosure	2		2
Liabilities, Fair Value Disclosure	3		2
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	1
Liabilities, Fair Value Disclosure	3
Energy Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Liabilities, Fair Value Disclosure	(12)	[1]	(15)	[1]
Energy Contracts [Member] | Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Liabilities, Fair Value Disclosure	(6)	[1]	(8)	[1]
Energy Contracts [Member] | TUCSON ELECTRIC POWER COMPANY
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Liabilities, Fair Value Disclosure	(3)	[1]	(3)	[1]
Energy Contracts [Member] | TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Liabilities, Fair Value Disclosure	$ (1)	[1]	$ 0	[1]

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

[2] ) TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilitie

[3] ) All of the option contracts relate to TE

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments (Detail) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Liabilities:
Long-Term Debt	$ (1,522,504,000)	$ (1,498,442,000)
TUCSON ELECTRIC POWER COMPANY
Liabilities:
Long-Term Debt	(1,223,505,000)	(1,223,442,000)
Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-Term Debt	(1,523,000,000)	1,498,000,000
Carrying Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Debt	0	9,000,000
Liabilities:
Long-Term Debt	(1,224,000,000)	(1,223,000,000)
Carrying Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Equity	36,000,000	36,000,000
Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-Term Debt	(1,572,000,000)	(1,583,000,000)
Fair Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Debt	0	9,000,000
Liabilities:
Long-Term Debt	(1,245,000,000)	(1,271,000,000)
Fair Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Equity	$ 24,000,000	$ 23,000,000

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 34,618	$ 26,273	$ 45,963	$ 32,749
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	933	280	1,544	272
Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax	68	55	137	163
Other Comprehensive Income (Loss), Net of Tax	1,001	335	1,681	435
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	35,619	26,608	47,644	33,184
TUCSON ELECTRIC POWER COMPANY
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	30,787	21,910	32,266	20,449
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	878	389	1,456	427
Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax	68	55	137	163
Other Comprehensive Income (Loss), Net of Tax	946	444	1,593	590
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	31,733	22,354	33,859	21,039
Retained Earnings [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			45,963
Retained Earnings [Member] | TUCSON ELECTRIC POWER COMPANY
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			$ 32,266

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

6 Months Ended

Jun. 30, 2013

COMMITMENTS, CONTINGENCIES, AND PROPOSED ENVIRONMENTAL MATTERS

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

In addition to those reported in our 2012 Annual Report on Form 10-K, we entered into the following new long-term commitments.

TEP COMMITMENTS

Purchase Power Contracts

TEP entered into new forward purchase power commitments that will settle through December 2014. Some of these contracts are at fixed prices per MWh and others are indexed to natural gas prices. Based on projected market prices as of June 30, 2013, TEP's estimated minimum payment obligations for these purchases are $9 million in 2014.

TEP has a 20-year Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $4 million per year in each of the next five years and approximately $56 million total thereafter.

RES Recoverable Incentives

In exchange for the environmental attributes, or RECs, TEP and UNS Electric make two types of incentive payments to customers who install distributed generation: up-front incentive payments and Performance-Based Incentives (PBIs). Both up-front incentive and PBI payments are recovered through the RES tariff. Up-front incentive payments are distinguished by the following:

• residential and small commercial customers;

• small installations; and

• up-front payment upon installation.

PBIs are distinguished by the following:

• large commercial customers;

• large installations; and

• based on metered renewable energy production over periods ranging from 9 to 20 years.

In the second quarter 2013, TEP's total obligation related to RES PBI payments over future periods increased by $4 million from $62 million on December 31, 2012, to $66 million on June 30, 2013.

UNS GAS COMMITMENTS

UNS Gas entered into new forward energy commitments that settle through May 2016 at fixed prices per million British thermal units (MMBtu). UNS Gas’ minimum payment obligations for these purchases are $3 million in 2014, $2 million in 2015, and $1 million in 2016.

UNS ELECTRIC COMMITMENTS

Purchase Power Contracts

UNS Electric entered into new forward purchase power commitments that will settle through September 2015 at fixed prices per MWh. UNS Electric’s minimum payment obligations for these purchases are $4 million in 2014 and $3 million in 2015.

RES Performance-Based Incentives

UNS Electric is contractually obligated to retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In 2013, UNS Electric's total obligation for RES PBIs increased by approximately $1 million, from $6 million on December 31, 2012, to $7 million on June 30, 2013. UNS Electric will make payments over periods ranging from 10 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff.

TEP CONTINGENCIES

Claim Related to San Juan Generating Station

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

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 matter is stayed until August 1, 2013 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.

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 Generating Station (Navajo), San Juan, and Four Corners. TEP’s share of reclamation costs is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) recorded was $17 million at June 30, 2013 and $16 million at December 31, 2012.

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

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

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric expect to abandon the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. See Note 2. In 2012, TEP recorded a regulatory asset of $5 million and UNS Electric recorded a regulatory asset of $0.2 million for the balance deemed probable of recovery.

Springerville Unit 1 Leases

The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030. TEP has a fair market value purchase option for facilities under the Springerville Unit 1 Leases, which requires TEP to issue notification of intent to purchase by August 31, 2013. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal process to determine the fair market value purchase price, in accordance with the Springerville Unit 1 Leases. Based on that appraisal, TEP has the option to pay $159 million in 2015 for the 86% interest not already owned by TEP. In 2012, TEP initiated a proceeding seeking judicial confirmation of the results of the appraisal process in Federal District Court. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for the leased interest. In January 2013, the Federal District Court denied TEP's petition on the grounds that the court lacks jurisdiction in the matter. In February 2013, TEP appealed the matter to the U.S. Court of Appeals for the Ninth Circuit, where it is currently pending. TEP cannot predict the outcome of this matter.

Resolution of Contingencies

Springerville Generating Station Unit 3 Outage

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

ENVIRONMENTAL MATTERS

Environmental Regulation

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

Hazardous Air Pollutant Requirements

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

Navajo

Based on the EPA’s final standards, Navajo may require mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. 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.

San Juan

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

Four Corners

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

Springerville Generating Station

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

Sundt Generating Station

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

Regional Haze Rules

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

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

Navajo

In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, reached an agreement that would achieve greater NOx emission reductions than the EPA's proposed BART rule. The stakeholder group has submitted the agreement for the EPA's consideration 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 required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.

San Juan

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

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

In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement that outlines an alternative to the FIP. The terms of the agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of Selective Non-Catalytic Reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW or 50%, of San Juan Units 1 and 2. At June 30, 2013, the book value of TEP's share of San Juan Units 1 and 2 was $214 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. TEP cannot predict the ultimate outcome of this matter.

Four Corners

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

Springerville

Provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018.

Sundt

In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule. Under the Regional Haze Rule, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART determination. The EPA postponed its expected release of a proposed BART requirement for Sundt Unit 4 until September 2013, with a final determination expected in February 2014.

Greenhouse Gas Regulation

On June 25, 2013, President Obama directed the EPA to move forward with regulations to limit carbon emissions from new and existing fossil fueled power plants.  Specifically, the President directed the EPA to issue a re-proposed rule for new power plants by September 20, 2013. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

Additionally, the President ordered the EPA to:

• propose carbon emission standards for existing power plants by June 1, 2014;

• finalize those standards by June 1, 2015; and

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

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Cash Flows from Operating Activities
Cash Receipts From Electric Retail Sales	$ 519,154	$ 510,264
Cash Receipts From Electric Wholesale Sales	82,273	75,153
Cash Receipts from Gas Retail Sales	91,207	95,063
Cash Receipts From Operating Spv Units Three And Four	49,974	47,720
Cash Receipts From Gas Wholesale Sales	3,494	438
Proceeds from Interest Received	516	2,277
Proceeds from Other Operating Activities	16,914	13,117
Fuel Costs Paid	(140,185)	(146,203)
Payment Of Operations And Maintenance Costs	(121,272)	(137,634)
Purchased Energy Costs Paid	(135,775)	(126,059)
Payments for Other Taxes	(90,554)	(89,972)
Payments to Employees	(68,004)	(66,680)
Interest Paid, Net	(34,662)	(37,986)
Capital Lease Interest Paid	(18,630)	(23,177)
Payments for Other Operating Activities	(6,798)	(3,777)
Net Cash Provided by (Used in) Operating Activities	147,652	112,544
Cash Flows from Investing Activities
Proceeds from Maturities, Prepayments and Calls of Held-to-maturity Securities	9,104	19,278
Proceeds from Note Receivable	0	5,000
Proceeds from Insurance Settlement, Investing Activities	0	2,875
Other Cash Receipts Investing Activities	9,482	10,540
Payments to Acquire Property, Plant, and Equipment	(155,685)	(166,204)
Payments for (Proceeds from) Other Investing Activities	(13,095)	(5,235)
Net Cash Provided by (Used in) Investing Activities	(150,194)	(133,746)
Cash Flows from Financing Activities
Proceeds from Lines of Credit	114,000	324,000
Proceeds from (Payments for) Other Financing Activities	4,314	2,277
Repayments of Lines of Credit	(48,000)	(159,000)
Repayments of Long-term Capital Lease Obligations	(84,206)	(76,236)
Common Stock Dividends Paid	(36,079)	(34,066)
Payments of Financing Costs	(982)	(1,948)
Repayments of Long-term Debt	0	(9,341)
Other Cash Payments Financing Activities	(730)	(606)
Net Cash Provided by (Used in) Financing Activities	(51,683)	45,080
Cash and Cash Equivalents, Period Increase (Decrease)	(54,225)	23,878
Cash and Cash Equivalents, Beginning of Period	123,918	76,390
Cash and Cash Equivalents, End of Period	69,693	100,268
TUCSON ELECTRIC POWER COMPANY
Cash Flows from Operating Activities
Cash Receipts From Electric Retail Sales	435,779	420,296
Cash Receipts From Electric Wholesale Sales	75,803	62,884
Cash Receipts From Operating Spv Units Three And Four	49,974	47,720
Cash Receipts From Gas Wholesale Sales	3,145	26
Reimbursement Of Affiliate Charges	12,695	11,437
Proceeds from Interest Received	509	1,523
Proceeds from Other Operating Activities	13,320	9,815
Fuel Costs Paid	(139,596)	(144,929)
Payment Of Operations And Maintenance Costs	(117,133)	(133,845)
Payments for Other Taxes	(68,574)	(67,013)
Payments to Employees	(57,483)	(55,185)
Purchased Power Costs Paid	(40,949)	(30,437)
Interest Paid, Net	(27,590)	(27,966)
Capital Lease Interest Paid	(18,630)	(23,177)
Income Taxes Paid	0	(1,796)
Payments for Other Operating Activities	(5,728)	(2,847)
Net Cash Provided by (Used in) Operating Activities	115,542	66,506
Cash Flows from Investing Activities
Proceeds from Maturities, Prepayments and Calls of Held-to-maturity Securities	9,104	19,278
Proceeds from Insurance Settlement, Investing Activities	0	2,875
Other Cash Receipts Investing Activities	7,920	7,111
Payments to Acquire Property, Plant, and Equipment	(118,210)	(142,385)
Payments to Acquire Intangible Assets	(11,390)	(4,207)
Net Cash Provided by (Used in) Investing Activities	(112,576)	(117,328)
Cash Flows from Financing Activities
Proceeds from Lines of Credit	78,000	184,000
Proceeds from (Payments for) Other Financing Activities	1,130	1,087
Repayments of Lines of Credit	(48,000)	(45,000)
Repayments of Long-term Capital Lease Obligations	(84,206)	(76,236)
Payments of Financing Costs	(982)	(1,948)
Repayments of Long-term Debt	0	(6,535)
Other Cash Payments Financing Activities	(534)	(440)
Net Cash Provided by (Used in) Financing Activities	(54,592)	54,928
Cash and Cash Equivalents, Period Increase (Decrease)	(51,626)	4,106
Cash and Cash Equivalents, Beginning of Period	79,743	27,718
Cash and Cash Equivalents, End of Period	$ 28,117	$ 31,824

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Operating Revenues
Electric Domestic Regulated Revenue	$ 285,419	$ 292,071	$ 506,279	$ 497,502
Sales Revenue from Energy Commodities and Services	30,654	25,511	65,052	59,127
Gas Retail Sales	20,013	20,006	71,002	70,215
Other Revenue, Net	29,131	26,410	55,025	52,540
Revenues	365,217	363,998	697,358	679,384
Operating Expenses
Utilities Operating Expense, Fuel Used	86,459	82,325	168,148	153,060
Utilities Operating Expense, Purchased Power	57,796	48,203	121,955	107,993
Cost of Transmission	4,521	3,412	7,707	6,238
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	2,074	14,215	(3,294)	11,654
Cost of Goods and Services, Energy Commodities and Services	150,850	148,155	294,516	278,945
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses	95,143	90,926	185,043	185,241
Cost of Services, Depreciation	36,671	35,190	72,970	70,174
Cost of Services, Amortization	8,119	9,112	16,408	17,776
Taxes, Miscellaneous	13,631	12,556	27,723	24,794
Utilities Operating Expense	304,414	295,939	596,660	576,930
Operating Income (Loss)	60,803	68,059	100,698	102,454
Other Income (Deductions)
Investment Income, Interest	19	383	28	641
Other Nonoperating Income	1,734	1,333	3,502	3,038
Other Nonoperating Expense	(807)	(484)	(1,380)	(937)
94	94	(344)	1,133	1,041
Nonoperating Income (Expense)	1,040	888	3,283	3,783
Interest and Debt Expense [Abstract]
Interest Expense, Debt	17,700	17,602	35,954	36,737
Interest Expense, Lessee, Assets under Capital Lease	6,249	8,301	12,498	16,598
Interest Expense, Other	346	315	(47)	1,020
Interest Expense, Capitalized	(745)	(655)	(1,420)	(1,186)
Interest Expense	23,550	25,563	46,985	53,169
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	38,293	43,384	56,996	53,068
Income Tax Expense (Benefit)	3,675	17,111	11,033	20,319
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	34,618	26,273	45,963	32,749
Weighted-Average Shares of Common Stock Outstanding (000)
Basic	41,598	40,471	41,569	39,251
Diluted	41,921	41,630	41,898	41,646
Earnings Per Share
Basic	$ 0.83	$ 0.65	$ 1.11	$ 0.83
Diluted	$ 0.83	$ 0.64	$ 1.10	$ 0.81
Dividends Declared Per Share	$ 0.435	$ 0.43	$ 0.87	$ 0.86
TUCSON ELECTRIC POWER COMPANY
Operating Revenues
Electric Domestic Regulated Revenue	243,635	247,770	428,515	414,101
Sales Revenue from Energy Commodities and Services	29,542	22,274	63,940	52,040
Other Revenue, Net	31,086	29,375	59,559	57,256
Revenues	304,263	299,419	552,014	523,397
Operating Expenses
Utilities Operating Expense, Fuel Used	84,553	79,554	165,351	149,528
Utilities Operating Expense, Purchased Power	28,410	20,862	47,338	34,488
Cost of Transmission	1,730	1,401	2,595	2,363
Increase (Decrease) to Reflect PPFAC Recovery Treatment	5,274	12,811	2,914	5,125
Cost of Goods and Services, Energy Commodities and Services	119,967	114,628	218,198	191,504
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses	82,011	78,683	159,835	161,149
Cost of Services, Depreciation	28,861	27,545	57,418	55,012
Cost of Services, Amortization	9,052	10,028	18,275	19,620
Taxes, Miscellaneous	10,939	10,324	22,108	20,009
Utilities Operating Expense	250,830	241,208	475,834	447,294
Operating Income (Loss)	53,433	58,211	76,180	76,103
Other Income (Deductions)
Investment Income, Interest	12	43	8	69
Other Nonoperating Income	1,270	1,209	2,438	2,286
Other Nonoperating Expense	(2,472)	(1,640)	(4,717)	(3,128)
94	94	(344)	1,133	1,041
Nonoperating Income (Expense)	(1,096)	(732)	(1,138)	268
Interest and Debt Expense [Abstract]
Interest Expense, Debt	13,991	13,378	28,564	27,294
Interest Expense, Lessee, Assets under Capital Lease	6,249	8,301	12,498	16,598
Interest Expense, Other	192	246	(168)	777
Interest Expense, Capitalized	(534)	(598)	(1,027)	(1,020)
Interest Expense	19,898	21,327	39,867	43,649
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	32,439	36,152	35,175	32,722
Income Tax Expense (Benefit)	1,652	14,242	2,909	12,273
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	30,787	21,910	32,266	20,449
Retained Earnings [Member]
Interest and Debt Expense [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			45,963
Retained Earnings [Member] | TUCSON ELECTRIC POWER COMPANY
Interest and Debt Expense [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			$ 32,266

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FAIR VALUE MEASUREMENTS & 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, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning Balance	$ (3)	$ 0	$ (5)	$ 0
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities - Derivative Instruments	(2)	0	(2)	0
Settlements	0	0	2	0
Ending Balance	(4)	0	(3)	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset And Liabilities Value	(5)	0	(5)	0
TUCSON ELECTRIC POWER COMPANY
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning Balance	(1)	0	0	0
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities - Derivative Instruments	0	0	(1)	0
Settlements	0	0	0	0
Ending Balance	0	0	(1)	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset And Liabilities Value	$ (1)	$ 0	$ (1)	$ 0

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UNS ENERGY EARNINGS PER SHARE (Tables)

6 Months Ended

Jun. 30, 2013

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,
	2013		2012		2013		2012
	Thousands of Dollars
Numerator:
Net Income	$	34,618	$	26,273	$	45,963	$	32,749
Income from Assumed Conversion of Convertible Senior Notes (1)	—		237		—		1,100
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	34,618	$	26,510	$	45,963	$	33,849
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,427		40,322		41,404		39,107
Fully Vested Deferred Stock Units	171		149		165		144
Total Weighted Average Common Stock Outstanding – Basic	41,598		40,471		41,569		39,251
Effect of Dilutive Securities:
Convertible Senior Notes (1)	—		909		—		2,125
Options and Stock Issuable Under Share-Based Compensation Plans	323		250		329		270
Total Weighted Average Common Stock Outstanding – Diluted	41,921		41,630		41,898		41,646

⁽¹⁾ In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

Number of Stock Options to Purchase Shares of Common Stock Excluded from Computation of Diluted Earning Per Share

We excluded the following outstanding stock options, with an exercise price above market, from our diluted EPS computation as their effect would be anti-dilutive:

	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
	Thousands of Shares
Stock Options	—	101	—	101

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FINANCIAL STATEMENT PRESENTATION FINANCIAL STATEMENT PRESENTATION (Tables)

6 Months Ended

Jun. 30, 2013

Disclosure Nature Of Operations And Basis Of Accounting Presentation Additional Information [Abstract]

Schedule of Error Corrections and Prior Period Adjustments [Table Text Block]

As a result, in accordance with GAAP, we revised our prior period income statement as follows:

	UNS Energy
	Three Months Ended				Six Months Ended
	June 30, 2012				June 30, 2012
	As Reported		As Revised		As Reported		As Revised
	Thousands of Dollars				Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	28,684	$	25,511	$	65,787	$	59,127
Purchased Energy	51,376		48,203		114,653		107,993
Total Fuel and Purchased Energy	151,328		148,155		285,605		278,945
Total Operating Expenses	299,112		295,939		583,590		576,930

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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		3 Months Ended		6 Months Ended		1 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 UNS Energy Corporation [Member]	Jun. 30, 2013 UNS Energy Corporation [Member]	Jun. 30, 2012 UNS Energy Corporation [Member]	Jun. 30, 2013 UNS Energy Corporation [Member]	Jun. 30, 2012 UNS Energy Corporation [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2012 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2012 TUCSON ELECTRIC POWER COMPANY	May 31, 2013 Restricted Stock Units (RSUs) [Member] Director [Member]	Feb. 28, 2013 Restricted Stock Units (RSUs) [Member] Officer [Member]	Feb. 28, 2013 Performance Shares [Member] Officer [Member]	Feb. 28, 2013 Based On Monte Carlo Simulation [Member] Performance Shares [Member] Officer [Member]	Feb. 28, 2013 Based On Cumulative Net Income [Member] Performance Shares [Member] Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Shares											8,870	21,560	43,120
Granted											$ 48.99	$ 46.23		$ 45.54	$ 46.23
Share based compensation expense, net of amounts capitalized		$ 1	$ 1	$ 1	$ 1	$ 1	$ 1	$ 1	$ 1	$ 1
Total unrecognized compensation expense on non-vested share-based compensation	$ 0
Total number of shares awarded but not yet issued, including target performance based shares under the share-based compensation plans	0

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UNS ENERGY EARNINGS PER SHARE - Number of Stock Options to Purchase Shares of Common Stock Excluded from Computation of Diluted Earning Per Share (Detail) (Stock Options [Member]) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Stock Options [Member]
Stock Options Excluded from the Diluted EPS Computation	0	101	0	101

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INCOME TAXES - Uncertain Tax Positions (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	6 Months Ended
	Feb. 28, 2013	Jun. 30, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits at December 31, 2012		$ 30
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions		1
Reductions Based on Settlements with Tax Authorities	(28)	(28)
Unrecognized Tax Benefits at June 30, 2013		3
TUCSON ELECTRIC POWER COMPANY
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits at December 31, 2012		23
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions		1
Reductions Based on Settlements with Tax Authorities	(22)	(22)
Unrecognized Tax Benefits at June 30, 2013		$ 2

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REGULATORY MATTERS Future Implications of Discontinuing Application of Regulatory Accounting (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
TUCSON ELECTRIC POWER COMPANY
Regulatory Liabilities [Line Items]
Potential Extraordinary Gains (Losses) from Discontinuing Application of Regulatory Accounting	$ 112
Potential After-Tax Loss in Accumulated Other Comprehensive Income From Discontinuing Application of Regulatory Accounting	76
Uns Gas Incorporated [Member]
Regulatory Liabilities [Line Items]
Potential Extraordinary Gains (Losses) from Discontinuing Application of Regulatory Accounting	24
Potential After-Tax Loss in Accumulated Other Comprehensive Income From Discontinuing Application of Regulatory Accounting	2
UNS ELECTRIC, INC. [Member]
Regulatory Liabilities [Line Items]
Potential After-Tax Loss in Accumulated Other Comprehensive Income From Discontinuing Application of Regulatory Accounting	$ 3

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BUSINESS SEGMENTS - Reconciling Adjustments of Income Statement Items in Consolidation (Detail) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Segment Reporting, Revenue Reconciling Item [Line Items]
365217	$ 365,217,000		$ 363,998,000		$ 697,358,000		$ 679,384,000
Revenue from External Customers	365,000,000		364,000,000		697,000,000		679,000,000
Operating Revenues - Intersegment					0	[1]	0	[1]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	34,618,000		26,273,000		45,963,000		32,749,000
Related Party Transaction, Other Revenues from Transactions with Related Party	0	[1]	0	[1]
TUCSON ELECTRIC POWER COMPANY
Segment Reporting, Revenue Reconciling Item [Line Items]
365217	304,263,000		299,419,000		552,014,000		523,397,000
Revenue from External Customers	300,000,000		295,000,000		543,000,000		515,000,000
Operating Revenues - Intersegment					9,000,000	[1]	8,000,000	[1]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	30,787,000		21,910,000		32,266,000		20,449,000
Related Party Transaction, Other Revenues from Transactions with Related Party	4,000,000	[1]	4,000,000	[1]
Uns Gas Incorporated [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenue from External Customers	21,000,000		21,000,000		73,000,000		73,000,000
Operating Revenues - Intersegment					1,000,000	[1]	2,000,000	[1]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	0		0		8,000,000		5,000,000
Related Party Transaction, Other Revenues from Transactions with Related Party	1,000,000	[1]	1,000,000	[1]
UNS ELECTRIC, INC. [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenue from External Customers	44,000,000		48,000,000		80,000,000		91,000,000
Operating Revenues - Intersegment					1,000,000	[1]	1,000,000	[1]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	4,000,000		4,000,000		6,000,000		7,000,000
Related Party Transaction, Other Revenues from Transactions with Related Party	0	[1]	0	[1]
Other [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenue from External Customers	0		0		1,000,000		0
Operating Revenues - Intersegment					8,000,000	[1]	9,000,000	[1]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	0		0		0		1,000,000
Related Party Transaction, Other Revenues from Transactions with Related Party	4,000,000	[1]	5,000,000	[1]
Reconciling Adjustments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenue from External Customers	0		0		0		0
Operating Revenues - Intersegment					(19,000,000)	[1]	(20,000,000)	[1]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	0		0		0		0
Related Party Transaction, Other Revenues from Transactions with Related Party	$ (9,000,000)	[1]	$ (10,000,000)	[1]

[1] Operating Revenues – Intersegment: TEP includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems, facilities, etc.) allocated to affiliates on a cost-causative basis; and sales of power to UNS Electric at third-party market prices. Other primarily includes meter reading services and supplemental workforce provided by an unregulated affiliate to the utilities.

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INCOME TAXES

6 Months Ended

Jun. 30, 2013

INCOME TAXES

INCOME TAXES

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

	UNS Energy					TEP
	Three Months Ended June 30,
	2013			2012		2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	14		$	15	$	12		$	13
State Income Tax Expense, Net of Federal Deduction	2			2		2			1
Investment Tax Credit Basis Difference	(11		)	—		(11		)	—
Other	(1		)	—		(1		)	—
Total Federal and State Income Tax Expense	$	4		$	17	$	2		$	14

	UNS Energy						TEP
	Six Months Ended June 30,
	2013			2012			2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	20		$	19		$	12		$	11
State Income Tax Expense, Net of Federal Deduction	3			2			2			2
Cash Surrender Value of Life Insurance	—			(1		)	—			(1		)
Investment Tax Credit Basis Difference	(11		)	—			(11		)	—
Other	(1		)	—			—			—
Total Federal and State Income Tax Expense	$	11		$	20		$	3		$	12

Investment Tax Credit Basis Difference Adjustment

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

Uncertain Tax Positions

We recognize tax benefits from uncertain tax positions if it is more likely than not that the tax position will be sustained on examination by the taxing authorities. Each uncertain tax position is recognized up to the amount most likely to be sustained on examination and adjusted with changes in facts and circumstances. A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	UNS Energy			TEP
	Millions of Dollars
Unrecognized Tax Benefits at December 31, 2012	$	30		$	23
Additions Based on Tax Positions Taken in the Current Year	1			1
Reduction of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(22		)
Unrecognized Tax Benefits at June 30, 2013	$	3		$	2

In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources.  These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation.  As a result of the IRS ruling in the first quarter of 2013, UNS Energy reduced unrecognized tax benefits by $28 million, and TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.

The IRS completed its audit of the 2009 and 2010 tax returns in March 2013 resulting in no change to the financial statements.

In April 2013, the IRS provided notice of intent to audit the 2011 tax returns.

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

6 Months Ended

Jun. 30, 2013

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

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

	UNS Energy
	Six Months Ended June 30,
	2013			2012
	Thousands of Dollars
Net Income	$	45,963		$	32,749
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	72,970			70,174
Amortization Expense	16,408			17,776
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	3,516			3,234
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,515			1,545
Provision for Retail Customer Bad Debts	936			1,571
Use of RECs for Compliance	8,106			3,055
Deferred Income Taxes	36,644			17,397
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—
Pension and Retiree Expense	11,391			10,927
Pension and Retiree Funding	(8,924		)	(10,957		)
Share-Based Compensation Expense	1,390			1,170
Allowance for Equity Funds Used During Construction	(2,463		)	(1,920		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(3,294		)	11,654
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(20,706		)	(19,547		)
Materials and Fuel Inventory	8,777			(21,597		)
Accounts Payable	(9,576		)	(2,594		)
Income Taxes	(15,980		)	2,062
Interest Accrued	(6,885		)	(7,839		)
Taxes Other Than Income Taxes	490			952
Other	15,413			2,732
Net Cash Flows – Operating Activities	$	147,652		$	112,544

	TEP
	Six Months Ended June 30,
	2013			2012
	Thousands of Dollars
Net Income	$	32,266		$	20,449
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	57,418			55,012
Amortization Expense	18,275			19,620
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	2,987			2,506
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,216			1,072
Provision for Retail Customer Bad Debts	711			1,104
Use of RECs for Compliance	7,414			2,622
Deferred Income Taxes	24,883			10,810
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—
Pension and Retiree Expense	9,939			9,644
Pension and Retiree Funding	(8,493		)	(9,856		)
Share-Based Compensation Expense	1,108			923
Allowance for Equity Funds Used During Construction	(1,763		)	(1,646		)
Increase (Decrease) to Reflect PPFAC Recovery	2,914			5,125
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(30,452		)	(34,287		)
Materials and Fuel Inventory	8,923			(21,189		)
Accounts Payable	(11		)	7,686
Income Taxes	(10,798		)	1,769
Interest Accrued	(6,886		)	(6,805		)
Taxes Other Than Income Taxes	2,295			3,454
Other	11,347			(1,507		)
Net Cash Flows – Operating Activities	$	115,542		$	66,506

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS - Environmental Matters (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Navajo [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure Related to Installation of Baghouses	$ 43
Estimated Future Annual Operating Costs For Mercury Emmission Control Equipment and Baghouses	1
Estimated Capital Cost if SCR is Required	42
Estimated Capital Expenditures Related to Installation of Mercury Control Equipment	1
Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1
Estimated Capital Cost if SCR is Required	35
Estimated Capital Expenditures Related to Installation of Mercury Control Equipment	1
Number of Units on Which SCR Technology has to be Installed	5
Estimated Annual Future Operating Costs for SCR Equipment	2
Springerville [Member]
Commitments And Contingencies [Line Items]
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	3
Estimated Capital Expenditures Related to Installation of Mercury Control Equipment	5
San Juan [Member]
Commitments And Contingencies [Line Items]
Number of Years Allowed For Installation of SCRS	5 years
Book Value of Generating Units	214
Estimated Annual Future Operating Costs for SCR Equipment	6
Estimated Capital Expenditures Related To Installation Of Selective Non Catalytic Reductions	25
Estimated Annual Future Operating Costs for SNCR Equipment	1
Generating Capacity in Jointly Owned Facility, MW	340
Percentage of Ownership in Generating Units 1 & 2	50.00%
San Juan [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Cost if SCR is Required	200
San Juan [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Cost if SCR is Required	$ 180

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SHARE-BASED COMPENSATION PLANS

6 Months Ended

Jun. 30, 2013

SHARE-BASED COMPENSATION PLANS

SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS

In May 2013, the UNS Energy Compensation Committee granted 8,870 restricted stock units to non-employee directors at a grant date fair value of $48.99 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. The grant date fair value was calculated by reducing the grant date share price by the present value of the dividends expected to be paid on the shares during the vesting period. Fully vested but undistributed non-employee director stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. We issue UNS Energy Common Stock (Common Stock) for the vested stock units in the January following the year the person is no longer a director.

In February 2013, the UNS Energy Compensation Committee granted 21,560 restricted stock units to certain management employees at a grant date fair value, based on the grant date share price, of $46.23 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. These restricted stock units accrue dividend equivalents, during the vesting period, which are distributed in shares of Common Stock upon vesting.

PERFOMANCE SHARES

In February 2013, the UNS Energy Compensation Committee granted 43,120 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $45.54 per share. Those awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Return to the companies included in the Edison Electric Institute Index during the performance period of January 1, 2013 through December 31, 2015. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date share price, of $46.23 per share and will be paid out in Common Stock based on cumulative net income for the three-year period ended December 31, 2015. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents, during the performance period, which are paid upon vesting.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded less than $1 million of share-based compensation expense for the three months ended June 30, 2013 and June 30, 2012. For the six months ended June 30, 2013 and June 30, 2012, UNS Energy and TEP recorded share-based compensation expense of $1 million .

At June 30, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At June 30, 2013, 1 million shares were awarded but not yet issued, including target performance based shares, under the share-based compensation plans.

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DEBT AND CREDIT FACILITIES

6 Months Ended

Jun. 30, 2013

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

We summarize below the significant changes to our debt from those reported in our 2012 Annual Report on Form 10-K.

TEP TAX-EXEMPT BONDS ISSUED

In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 1, 2023. The proceeds from the sale of the bonds, together with $0.5 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received nor disbursed by TEP. TEP capitalized approximately $1 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statement through September 2029, the term of the bonds.

UNS ENERGY'S AND TEP'S CREDIT RATING UPGRADES

In June 2013, as a result of an upgrade in the senior secured rating of UNS Energy and a senior unsecured rating of TEP, the following agreements, with pricing tied to credit ratings for short-term borrowings, changed:

• Under the UNS Credit Agreement, the interest rate decreased from London Interbank Offered Rate (LIBOR) plus 1.75% to LIBOR plus 1.5%;

• Under the TEP Credit Agreement, the interest rate decreased from LIBOR plus 1.125% to LIBOR plus 1.0% ; and the margin rate on the $186 million letter of credit facility decreased from 1.125% to 1.0% ; and

• Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit decreased from 1.5% to 1.25% per annum.

COVENANT COMPLIANCE

At June 30, 2013, we were in compliance with the terms of our credit agreements, UNS Electric's term loan, and TEP's reimbursement agreement.

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CONDENSED 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 ($)	Accumulated Earnings/(Deficit) [Member] USD ($)	Accumulated Earnings/(Deficit) [Member] TUCSON ELECTRIC POWER COMPANY USD ($)	Accumulated Other Comprehensive Loss [Member] USD ($)	Accumulated Other Comprehensive Loss [Member] TUCSON ELECTRIC POWER COMPANY USD ($)	Capital Stock Expense [Member] TUCSON ELECTRIC POWER COMPANY USD ($)
Balances at Dec. 31, 2012		$ 1,065,465	$ 860,927		$ 882,138	$ 888,971	$ 193,117	$ (12,157)	$ (9,790)	$ (9,530)	$ (6,357)
Balances, shares at Dec. 31, 2012				41,344
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		45,963	32,266				45,963	32,266
Other Comprehensive Income (Loss), Net of Tax		1,681	1,593						1,681	1,593
Comprehensive Income (Loss), Net of Tax, Attributable to Parent		47,644	33,859
Dividends, Including Non-Cash Dividend Equivalents		(36,380)					(36,380)
Stock Issued During Period, Shares, Dividend Reinvestment Plan				4
Stock Issued During Period, Value, Dividend Reinvestment Plan		191			191
Shares Issued for Stock Options		1,170			1,170
Shares Issued for Stock Options, shares				36
Shares Issued Under Performance Share Awards		0			0
Shares Issued Under Performance Share Awards, shares				57
Other		330			330
Balances at Jun. 30, 2013		1,078,420	894,786		883,829	888,971	202,700	20,109	(8,109)	(7,937)	(6,357)
Balances, shares at Jun. 30, 2013	[1]			41,441
Balances at Mar. 31, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		34,618	30,787
Other Comprehensive Income (Loss), Net of Tax		1,001	946
Comprehensive Income (Loss), Net of Tax, Attributable to Parent		35,619	31,733
Balances at Jun. 30, 2013		$ 1,078,420	$ 894,786			$ 888,971					$ (6,357)

[1] UNS Energy has 75 million authorized shares of Common Stock.

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS - Credit Risk (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Derivative [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	$ (30)
Additional Collateral, Aggregate Fair Value	(30)
Impact Of Credit Risk On Fair Value Of Derivatives	0.1
TUCSON ELECTRIC POWER COMPANY
Derivative [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	(13)
Additional Collateral, Aggregate Fair Value	$ (13)

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

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REGULATORY MATTERS - Additional Information (Detail) (USD $)	6 Months Ended		1 Months Ended	6 Months Ended		1 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 UNS ELECTRIC, INC. [Member]	Jun. 30, 2013 Minimum [Member] UNS ELECTRIC, INC. [Member]	Jun. 30, 2013 Maximum [Member] UNS ELECTRIC, INC. [Member]	Jun. 30, 2013 Before July 1, 2013 [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 After June 30, 2013 [Member] TUCSON ELECTRIC POWER COMPANY
2013 TEP Rate Order
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided			4 years
Base Rate Increase Approved			$ 76,000,000
Fair value of rate base			2,300,000,000			286
Requested Rate of Return on Equity						10.50%
Requested Long Term Cost of Debt						5.97%
Requested Equity Portion of Capital Structure						53.00%
Requested Long Term Debt Portion of Capital Structure						47.00%
Approved Rate of Return on Equity			10.00%
Approved Long Term Cost of Debt			5.18%
Approved Short-Term Cost of Debt			1.42%
Approved Weighted Average Cost of Capital			7.26%
Approved Equity Portion of Capital Structure			43.50%
Approved Long Term Debt Portion of Capital Structure			56.00%
Approved Short-Term Debt Portion of Capital Structure			0.50%
Approved Rate of Return on the Fair Value Increment of Rate Base			0.68%
Original Cost Rate Base			1,500,000,000			217,000,000
Requested Return on Fair Value Increment of Rate Base						1.60%
Fair Value Increment Of Rate Base			800,000,000			0
Change in Composite Rate									3.32%	3.00%
Expected Change in Annual Depreciation			0	0
Purchased Power And Fuel Adjustment Clause Rate			0.001388
PPFAC Reduction - TEP Rate Order	3,000,000	0	3,000,000	3,000,000	0
Deferred Costs Related to San Juan Mine Fire			10,000,000
Cap on Increase in Lost Fixed Cost Recovery Rate			1.00%
Environmental Compliance Adjustor Capped Rate			0.00025
Retail Revenue Cap on Environmental Compliance Adjustor			0.25%
Proposed Base Rate Increase						$ 7,500,000
Percentage Increase In Base Rates Requested By Regulator						4.60%
ACC Staff and Others Rate Increase Recommendation							0.00%	0.80%

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SUPPLEMENTAL CASH FLOW INFORMATION

6 Months Ended

Jun. 30, 2013

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,
	2013			2012
	Thousands of Dollars
Net Income	$	45,963		$	32,749
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	72,970			70,174
Amortization Expense	16,408			17,776
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	3,516			3,234
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,515			1,545
Provision for Retail Customer Bad Debts	936			1,571
Use of RECs for Compliance	8,106			3,055
Deferred Income Taxes	36,644			17,397
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—
Pension and Retiree Expense	11,391			10,927
Pension and Retiree Funding	(8,924		)	(10,957		)
Share-Based Compensation Expense	1,390			1,170
Allowance for Equity Funds Used During Construction	(2,463		)	(1,920		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(3,294		)	11,654
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(20,706		)	(19,547		)
Materials and Fuel Inventory	8,777			(21,597		)
Accounts Payable	(9,576		)	(2,594		)
Income Taxes	(15,980		)	2,062
Interest Accrued	(6,885		)	(7,839		)
Taxes Other Than Income Taxes	490			952
Other	15,413			2,732
Net Cash Flows – Operating Activities	$	147,652		$	112,544

	TEP
	Six Months Ended June 30,
	2013			2012
	Thousands of Dollars
Net Income	$	32,266		$	20,449
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	57,418			55,012
Amortization Expense	18,275			19,620
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	2,987			2,506
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,216			1,072
Provision for Retail Customer Bad Debts	711			1,104
Use of RECs for Compliance	7,414			2,622
Deferred Income Taxes	24,883			10,810
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—
Pension and Retiree Expense	9,939			9,644
Pension and Retiree Funding	(8,493		)	(9,856		)
Share-Based Compensation Expense	1,108			923
Allowance for Equity Funds Used During Construction	(1,763		)	(1,646		)
Increase (Decrease) to Reflect PPFAC Recovery	2,914			5,125
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(30,452		)	(34,287		)
Materials and Fuel Inventory	8,923			(21,189		)
Accounts Payable	(11		)	7,686
Income Taxes	(10,798		)	1,769
Interest Accrued	(6,886		)	(6,805		)
Taxes Other Than Income Taxes	2,295			3,454
Other	11,347			(1,507		)
Net Cash Flows – Operating Activities	$	115,542		$	66,506

Non-Cash Transactions

In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. See Note 5.

In the first six months of 2012, UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Stock, resulting in non-cash transactions.

In the first six months of 2012, TEP's redemption of $193 million of tax-exempt bonds resulted in non-cash transactions.

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 30, 2013

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,
	2013			2012			2013		2012
	Millions of Dollars
Service Cost	$	3		$	2		$	1	$	1
Interest Cost	4			4			1		1
Expected Return on Plan Assets	(5		)	(4		)	—		—
Actuarial Loss Amortization	2			2			—		—
Net Periodic Benefit Cost	$	4		$	4		$	2	$	2

	Pension Benefits						Other Retiree Benefits
	Six Months Ended June 30,
	2013			2012			2013		2012
	Millions of Dollars
Service Cost	$	6		$	5		$	2	$	1
Interest Cost	8			8			1		2
Expected Return on Plan Assets	(10		)	(9		)	—		—
Actuarial Loss Amortization	4			4			—		—
Net Periodic Benefit Cost	$	8		$	8		$	3	$	3

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REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

6 Months Ended

Jun. 30, 2013

REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPIONENT (Notes)

6 Months Ended

Jun. 30, 2013

Statement of Other Comprehensive Income [Abstract]

Changes in Accumulated Other Comprehensive Income by Component

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The realized changes in accumulated other comprehensive income by component are as follows:

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Three Months Ended June 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(346	)	$	(293	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(604		)	(604		)	Interest Expense Capital Leases
Commodity Contracts	(191		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	451			429
Realized Losses on Cash Flow Hedges, Net of Taxes	(690		)	(659		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(111		)	(111		)	Other Expense
Tax Benefit	43			43
Amortization, Net of Taxes	(68		)	(68		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(758	)	$	(727	)

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Six Months Ended June 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(676	)	$	(575	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,208		)	(1,208		)	Interest Expense Capital Leases
Commodity Contracts	(191		)	(191		)	Purchased Energy/Purchased Power
Tax Benefit	820			781
Realized Losses on Cash Flow Hedges, Net of Taxes	(1,255		)	(1,193		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(222		)	(222		)	Other Expense
Tax Benefit	85			85
Amortization, Net of Taxes	(137		)	(137		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(1,392	)	$	(1,330	)

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Document and Entity Information In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jul. 17, 2013
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
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 Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		41,483,662
TUCSON ELECTRIC POWER COMPANY
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		32,139,434

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

6 Months Ended

Jun. 30, 2013

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT

The Financial Accounting Standards Board issued authoritative guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. Upon implementation entities will continue reporting their obligations under joint and several arrangements. In addition, the entity must measure, recognize, and disclose in the financial statements amounts they expect to pay on behalf of co-obligors for fixed obligations as of the balance sheet date. This guidance will be effective in the first quarter of 2014. We are evaluating the impact to our financial statements and disclosures.