UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

OR

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

For the transition period from                     to                     .

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

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

UNS Energy Corporation                         Yes  x    No  ¨

Tucson Electric Power Company             Yes  x    No  ¨

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

UNS Energy Corporation                         Yes  x    No   ¨

Tucson Electric Power Company             Yes  x    No  ¨

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

UNS Energy Corporation	Large accelerated filer	x	Accelerated filer	¨
	Non-accelerated filer	¨
	Smaller reporting company	¨

Tucson Electric Power Company	Large accelerated filer	¨	Accelerated filer	¨
	Non-accelerated filer	x
	Smaller reporting company	¨

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

UNS Energy Corporation                         Yes  ¨    No  x

Tucson Electric Power Company             Yes  ¨    No  x

As of July 18, 2012, 41,265,837 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of July 18, 2012, 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.

Table of Contents

Definitions	v
PART I
Reports of Independent Registered Public Accounting Firm	1
Item 1. – Financial Statements	3
UNS Energy Corporation
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
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. Nature of Operations and Basis of Accounting Presentation	15
Note 2. Regulatory Matters	16
Note 3. Business Segments	17
Note 4. Debt and Credit Facilities	19
Note 5. Income Taxes	20
Note 6. Commitments, Contingencies, and Proposed Environmental Matters	20
Note 7. Employee Benefit Plans	25
Note 8. Share-Based Compensation Plans	26
Note 9. Fair Value Measurements	26
Note 10. UNS Energy Earnings Per Share	32
Note 11. Millennium Investments	33
Note 12. Supplemental Cash Flow Information	34
Note 13. Derivative Instruments and Hedging Activities	35
Note 14. Review by Independent Registered Public Accounting Firm	38
Item  2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
UNS Energy Consolidated	39
Overview of Consolidated Business	39
Outlook and Strategies	40
Results of Operations	40
Liquidity and Capital Resources	42
Tucson Electric Power Company	45
Results of Operations	45
Factors Affecting Results of Operations	53
Liquidity and Capital Resources	58
UNS Gas	61
Results of Operations	61
Factors Affecting Results of Operations	63
Liquidity and Capital Resources	65
UNS Electric	66
Results of Operations	66
Factors Affecting Results of Operations	68
Liquidity and Capital Resources	69
Other Non-Reportable Business Segments	71
Results of Operations	71
Factors Affecting Results of Operations	71
Critical Accounting Estimates	71
Safe Harbor for Forward-Looking Statements	71

iii

Item 3. – Quantitative and Qualitative Disclosures about Market Risk	72
Item 4. – Controls and Procedures	72
PART II – OTHER INFORMATION
Item 1. – Legal Proceedings	73
Item 1A. – Risk Factors	73
Item 2. – Unregistered Sale of Equity Securities and Use of Proceeds	73
Item 5. – Other Information	74
Comprehensive Income	74
Ratio of Earnings to Fixed Charges	75
Environmental Matters	75
Item 6. Exhibits	78
Signatures	79
Exhibit Index	80

iv

DEFINITIONS

The abbreviations and acronyms used in the 2012 second 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
2008 TEP Rate Order	A rate order issued by the ACC resulting in a new retail rate structure for TEP, effective December 1, 2008
2010 TEP Reimbursement Agreement	Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
ACC	Arizona Corporation Commission
AFUDC	Allowance for Funds Used During Construction
APS	Arizona Public Service Company
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
BART BHP BMGS	Best Available Retrofit Technology BHP Minerals International, Inc. Black Mountain Generating Station
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
CCRs Circuit Court Common Stock	Coal Combustion Residuals United States Court of Appeals UNS Energy Corporation’s common stock, without par value
Company Convertible Senior Notes Cooling Degree Days	UNS Energy Corporation and its subsidiaries UNS Energy Corporation’s 4.5% Convertible Senior Notes An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DSM	Demand Side Management
ECA EEIP Electric EE Standards Energy	Environmental Compliance Adjustor Energy Efficiency Implementation Plan Electric Energy Efficiency Standards The amount of power produced over a given period of time measured in Megawatt-hours
EPA	Environmental Protection Agency
EPS FERC FIP	Earnings Per Share Federal Energy Regulatory Commission Federal Implementation Plan
Four Corners	Four Corners Generating Station
GAAP Gas EE Standards GBtu	Generally Accepted Accounting Principles Gas Energy Efficiency Standards Billion British thermal units
GWh Heating Degree Days	Gigawatt-hour(s) 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
kWh	Kilowatt-hour(s)
LFCR	Lost Fixed Cost Recovery Mechanism
LIBOR	London Interbank Offered Rate
Luna	Luna Generating Station
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation
MMBtu Mortgage Bonds	Million British thermal units Mortgage Bonds issued under the 1992 Mortgage
MW	Megawatt(s)
MWh	Megawatt-hour(s)

v

Navajo O&M NSP NTUA	Navajo Generating Station Operations and Maintenance Expense Negotiated Sales Program Navajo Tribal Utility Authority
NOx PGA	Nitrogen oxide 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
PNMR PPA PPFAC	PNM Resources, Incorporated, PNM’s parent company Power Purchase Agreement Purchased Power and Fuel Adjustment Clause
PSD RCRA RES	Prevention of Significant Deterioration Resource Conservation and Recovery Act Renewable Energy Standard
Retail Rates	Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service
San Juan	San Juan Generating Station
SERP	Supplemental Executive Retirement Plan
SCR SES SJCC SMCRA SO2 Springerville	Selective Catalytic Reduction Southwest Energy Solutions, a wholly-owned subsidiary of Millennium San Juan Coal Company Surface Mine Control and Reclamation Act Sulfur dioxide Springerville Generating Station
Springerville Common Facilities	Facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities Leases	Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1	Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases	Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2	Unit 2 of the Springerville Generating Station
Springerville Unit 3	Unit 3 of the Springerville Generating Station
Springerville Unit 4	Unit 4 of the Springerville Generating Station
SRP	Salt River Project Agricultural Improvement and Power District
Sundt	H. Wilson Sundt Generating Station
Sundt Unit 4	Unit 4 of the H. Wilson Sundt Generating Station
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 Letter of Credit Facility TEP Revolving Credit Facility	Letter of credit facility under the TEP Credit Agreement 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., an 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 Energy	UNS Energy Corporation
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES
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)

vi

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, 2012, and the related condensed consolidated statements of income for the three and six-month periods ended June 30, 2012 and 2011, the condensed consolidated statements of comprehensive income for the three and six-month periods ended June 30, 2012 and 2011, the condensed consolidated statement of changes in stockholders' equity for the six-month period ended June 30, 2012, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2012 and 2011. 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 as of December 31, 2011, and the related consolidated statements of income, of cash flows, of capitalization, and of changes in stockholders' equity and comprehensive income for the year then ended (not presented herein), and in our report dated February 27, 2012, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2011, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

July 30, 2012

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, 2012, and the related condensed consolidated statements of income for the three and six-month periods ended June 30, 2012 and 2011, the condensed consolidated statements of comprehensive income for the three and six-month periods ended June 30, 2012 and 2011, the condensed consolidated statement of changes in stockholder’s equity for the six-month period ended June 30, 2012, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2012 and 2011. 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 as of December 31, 2011, and the related consolidated statements of income, of cash flows, of capitalization, and of changes in stockholder's equity and comprehensive income for the year then ended (not presented herein), and in our report dated February 27, 2012, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2011, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

July 30, 2012

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,
2012			2011				2012			2011
(Unaudited)							(Unaudited)
-Thousands of Dollars-							-Thousands of Dollars-
(Except Per Share Amounts)							(Except Per Share Amounts)
						Operating Revenues
$	292,071		$	275,616		Electric Retail Sales	$	497,502		$	492,831
	28,684			38,744		Electric Wholesale Sales		65,787			79,658
	20,006			25,020		Gas Retail Sales		70,215			82,210
	26,410			30,293		Other Revenues		52,540			59,740
	367,171			369,673		Total Operating Revenues		686,044			714,439
						Operating Expenses
	82,325			81,949		Fuel		153,060			153,141
	51,376			66,336		Purchased Energy		114,653			144,610
	3,412			3,464		Transmission		6,238			5,966
	14,215			3,790		Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		11,654			(1,599	)
	151,328			155,539		Total Fuel and Purchased Energy		285,605			302,118
	90,926			90,052		Other Operations and Maintenance		185,241			191,107
	35,190			33,310		Depreciation		70,174			66,100
	9,112			7,253		Amortization		17,776			14,631
	12,556			12,229		Taxes Other Than Income Taxes		24,794			24,374
	299,112			298,383		Total Operating Expenses		583,590			598,330
	68,059			71,290		Operating Income		102,454			116,109
						Other Income (Deductions)
	383			826		Interest Income		641			1,820
	1,333			2,646		Other Income		4,079			5,477
	(828	)		(813	)	Other Expense		(937	)		(1,417	)
	888			2,659		Total Other Income (Deductions)		3,783			5,880
						Interest Expense
	17,602			18,203		Long-Term Debt		36,737			36,296
	8,301			9,931		Capital Leases		16,598			19,860
	(340	)		(109	)	Other Interest Expense, Net of Interest Capitalized		(166	)		(1,030	)
	25,563			28,025		Total Interest Expense		53,169			55,126
	43,384			45,924		Income Before Income Taxes		53,068			66,863
	17,111			17,320		Income Tax Expense		20,319			24,787
$	26,273		$	28,604		Net Income	$	32,749		$	42,076
						Weighted-Average Shares of Common Stock Outstanding (000)
	40,471			36,950		Basic		39,251			36,869
	41,630			41,555		Diluted		41,646			41,477
						Earnings Per Share
$	0.65		$	0.77		Basic	$	0.83		$	1.14
$	0.64		$	0.71		Diluted	$	0.81		$	1.07
$	0.43		$	0.42		Dividends Declared Per Share	$	0.86		$	0.84

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,
2012			2011				2012			2011
(Unaudited)							(Unaudited)
-Thousands of Dollars-							-Thousands of Dollars-
						Comprehensive Income
$	26,273		$	28,604		Net Income	$	32,749		$	42,076
						Other Comprehensive Income (Loss)
	(224	)		(1,342	)	Unrealized Gain (Loss) on Cash Flow Hedges, net of $146 and $994 income taxes net of $697 and $762 income taxes		(1,063	)		(1,163	)
						Reclassification of Realized Losses
						on Cash Flow Hedges to Net Income,
	504			498		net of $(330) and $(326) income taxes
						net of $(874) and $(431) income taxes		1,335			659
						Supplemental Executive Retirement Plan
						(SERP) Benefit Adjustments,
	55			23		net of $(34) and $(95) income taxes
						net of $(15) and $(95) income taxes		163			149
	335			(821	)	Total Other Comprehensive Income (Loss), Net of Income Taxes		435			(355	)
$	26,608		$	27,783		Total Comprehensive Income	$	33,184		$	41,721

See Notes to Condensed Consolidated Financial Statements.

4

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2012			2011
	(Unaudited)
	-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	510,264		$	505,446
Cash Receipts from Electric Wholesale Sales		75,153			89,266
Cash Receipts from Gas Retail Sales		95,063			104,208
Cash Receipts from Operating Springerville Units 3 & 4		47,720			54,206
Interest Received		2,277			3,856
Performance Deposits Received		—			4,700
Other Cash Receipts		13,555			12,187
Fuel Costs Paid		(149,722	)		(124,261	)
Purchased Energy Costs Paid		(126,059	)		(143,900	)
Payment of Other Operations and Maintenance Costs		(134,115	)		(142,502	)
Wages Paid, Net of Amounts Capitalized		(66,680	)		(62,476	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(89,972	)		(87,102	)
Interest Paid, Net of Amounts Capitalized		(37,986	)		(33,582	)
Capital Lease Interest Paid		(23,177	)		(23,821	)
Performance Deposits Paid		—			(3,340	)
Income Taxes Paid		—			(700	)
Other Cash Payments		(3,777	)		(3,096	)
Net Cash Flows—Operating Activities		112,544			149,089
Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt		19,278			38,353
Proceeds from Note Receivable		5,000			—
Insurance Proceeds for Replacement Assets		2,875			—
Other Cash Receipts		10,540			6,984
Capital Expenditures		(166,204	)		(174,113	)
Purchase of Intangibles—Renewable Energy Credits		(5,010	)		(2,529	)
Other Cash Payments		(225	)		(578	)
Net Cash Flows—Investing Activities		(133,746	)		(131,883	)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities		324,000			160,000
Proceeds from Issuance of Long-Term Debt		—			11,080
Proceeds from Stock Options Exercised		287			6,541
Other Cash Receipts		1,990			2,573
Repayments of Borrowings Under Revolving Credit Facilities		(159,000	)		(70,000	)
Payments of Capital Lease Obligations		(76,236	)		(62,473	)
Common Stock Dividends Paid		(34,066	)		(30,881	)
Repayments of Long-Term Debt		(9,341	)		(2,840	)
Payment of Debt Issue/Retirement Costs		(1,948	)		(282	)
Other Cash Payments		(606	)		(744	)
Net Cash Flows—Financing Activities		45,080			12,974
Net Increase in Cash and Cash Equivalents		23,878			30,180
Cash and Cash Equivalents, Beginning of Year		76,390			67,599
Cash and Cash Equivalents, End of Period	$	100,268		$	97,779

See Note 12 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

5

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2012			December 31, 2011
	(Unaudited)
	-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service	$	4,930,976		$	4,856,108
Utility Plant Under Capital Leases		582,669			582,669
Construction Work in Progress		115,673			89,749
Total Utility Plant		5,629,318			5,528,526
Less Accumulated Depreciation and Amortization		(1,905,629	)		(1,869,300	)
Less Accumulated Amortization of Capital Lease Assets		(485,688	)		(476,963	)
Total Utility Plant—Net		3,238,001			3,182,263
Investments and Other Property
Investments in Lease Debt and Equity		36,411			65,829
Other		33,528			34,205
Total Investments and Other Property		69,939			100,034
Current Assets
Cash and Cash Equivalents		100,268			76,390
Accounts Receivable—Customer		104,545			98,633
Unbilled Accounts Receivable		67,047			51,464
Allowance for Doubtful Accounts		(6,129	)		(5,572	)
Fuel Inventory		50,236			33,263
Materials and Supplies		87,273			82,649
Regulatory Assets—Current		88,605			97,056
Deferred Income Taxes—Current		25,783			23,158
Derivative Instruments		8,735			11,966
Other		37,020			32,577
Total Current Assets		563,383			501,584
Regulatory and Other Assets
Regulatory Assets—Noncurrent		159,265			173,199
Other Assets		33,722			32,199
Total Regulatory and Other Assets		192,987			205,398
Total Assets	$	4,064,310		$	3,989,279

See Notes to Condensed Consolidated Financial Statements.

(Continued)

6

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2012		2011
	(Unaudited)
	-Thousands of Dollars-
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,038,454	$	888,474
Capital Lease Obligations		276,524		352,720
Long-Term Debt		1,386,878		1,517,373
Total Capitalization		2,701,856		2,758,567
Current Liabilities
Current Obligations Under Capital Leases		88,112		77,482
Borrowing Under Revolving Credit Facilities		149,000		10,000
Accounts Payable—Trade		90,799		109,760
Interest Accrued		18,487		38,302
Accrued Taxes Other than Income Taxes		42,949		41,997
Accrued Employee Expenses		17,992		24,917
Customer Deposits		32,979		32,485
Regulatory Liabilities—Current		45,288		41,911
Derivative Instruments		29,890		36,467
Other		14,668		9,198
Total Current Liabilities		530,164		422,519
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent		309,856		300,326
Regulatory Liabilities—Noncurrent		258,391		234,945
Derivative Instruments		16,498		20,403
Pension and Other Postretirement Benefits		135,721		139,356
Other		111,824		113,163
Total Deferred Credits and Other Liabilities		832,290		808,193
Commitments, Contingencies, and Proposed Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$	4,064,310	$	3,989,279

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

7

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

								Accumulated
	Common							Other			Total
	Shares		Common		Accumulated			Comprehensive			Stockholders’
	Outstanding*		Stock		Earnings			Loss			Equity
	(Unaudited)
	-Thousands of Dollars-
Balances at December 31, 2011		36,918	$	725,903	$	172,655		$	(10,084	)	$	888,474
Comprehensive Income
2012 Year-to-Date Net Income						32,749						32,749
Other Comprehensive Income, net of $(192) income taxes									435			435
Total Comprehensive Income												33,184
Dividends, Including Non-Cash Dividend Equivalents						(34,256	)					(34,256	)
Shares Issued on Conversion of Notes and Related Tax Effect		4,262		149,805								149,805
Shares Issued for Stock Options		12		227								227
Shares Issued Under Performance Share Awards		31
Other				1,020								1,020
Balances at June 30, 2012		41,223	$	876,955	$	171,148		$	(9,649	)	$	1,038,454

* 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,
2012			2011				2012			2011
(Unaudited)							(Unaudited)
- Thousands of Dollars -							-Thousands of Dollars-
						Operating Revenues
$	247,770		$	231,652		Electric Retail Sales	$	414,101		$	405,354
	22,274			31,759		Electric Wholesale Sales		52,040			67,015
	29,375			31,822		Other Revenues		57,256			62,452
	299,419			295,233		Total Operating Revenues		523,397			534,821
						Operating Expenses
	79,554			80,217		Fuel		149,528			150,587
	20,862			26,445		Purchased Power		34,488			43,680
	1,401			1,232		Transmission		2,363			1,927
	12,811			2,675		Increase (Decrease) to Reflect PPFAC Recovery Treatment		5,125			(6,262	)
	114,628			110,569		Total Fuel and Purchased Energy		191,504			189,932
	78,683			78,094		Other Operations and Maintenance		161,149			166,587
	27,545			25,850		Depreciation		55,012			51,583
	10,028			8,180		Amortization		19,620			16,484
	10,324			10,043		Taxes Other Than Income Taxes		20,009			19,947
	241,208			232,736		Total Operating Expenses		447,294			444,533
	58,211			62,497		Operating Income		76,103			90,288
						Other Income (Deductions)
	43			582		Interest Income		69			1,317
	1,209			1,719		Other Income		3,327			4,367
	(1,984	)		(2,490	)	Other Expense		(3,128	)		(4,996	)
	(732	)		(189	)	Total Other Income (Deductions)		268			688
						Interest Expense
	13,378			12,157		Long-Term Debt		27,294			24,412
	8,301			9,930		Capital Leases		16,598			19,859
	(352	)		(91	)	Other Interest Expense, Net of Interest Capitalized		(243	)		(837	)
	21,327			21,996		Total Interest Expense		43,649			43,434
	36,152			40,312		Income Before Income Taxes		32,722			47,542
	14,242			15,154		Income Tax Expense		12,273			17,681
$	21,910		$	25,158		Net Income	$	20,449		$	29,861

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,
2012			2011				2012			2011
(Unaudited)							(Unaudited)
- Thousands of Dollars -							-Thousands of Dollars-
						Comprehensive Income
$	21,910		$	25,158		Net Income	$	20,449		$	29,861
						Other Comprehensive Income (Loss)
	(94	)		(1,342	)	Unrealized Gain (Loss) on Cash Flow Hedges, net of $62 and $994 income taxes net of $565 and $762 income taxes		(862	)		(1,163	)
	483			498		Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(317) and $(326) income taxes net of $(844) and $(431) income taxes		1,289			659
	55			23		SERP Benefit Adjustments, net of $(34) and $(95) income taxes net of $(15) and $(95) income taxes		163			149
	444			(821	)	Total Other Comprehensive Income (Loss), Net of Income Taxes		590			(355	)
$	22,354		$	24,337		Total Comprehensive Income	$	21,039		$	29,506

See Notes to Condensed Consolidated Financial Statements.

10

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2012			2011
	(Unaudited)
	-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	420,296		$	409,089
Cash Receipts from Electric Wholesale Sales		62,884			77,696
Cash Receipts from Operating Springerville Units 3 & 4		47,720			54,206
Reimbursement of Affiliate Charges		11,437			9,758
Interest Received		1,523			3,823
Income Tax Refunds Received		200			1,805
Other Cash Receipts		9,641			8,088
Fuel Costs Paid		(148,448	)		(123,040	)
Payment of Other Operations and Maintenance Costs		(130,326	)		(139,613	)
Wages Paid, Net of Amounts Capitalized		(55,185	)		(51,042	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(67,013	)		(63,338	)
Purchased Power Costs Paid		(30,437	)		(30,332	)
Capital Lease Interest Paid		(23,177	)		(23,821	)
Interest Paid, Net of Amounts Capitalized		(27,966	)		(22,245	)
Performance Deposit Payments		—			(1,140	)
Income Taxes Paid		(1,796	)		(1,811	)
Other Cash Payments		(2,847	)		(1,841	)
Net Cash Flows – Operating Activities		66,506			106,242
Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt		19,278			38,353
Insurance Proceeds for Replacement Assets		2,875			—
Other Cash Receipts		7,111			4,478
Capital Expenditures		(142,385	)		(130,395	)
Purchase of Intangibles – Renewable Energy Credits		(4,207	)		(2,601	)
Other Cash Payments		—			(558	)
Net Cash Flows – Investing Activities		(117,328	)		(90,723	)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility		184,000			110,000
Proceeds from Issuance of Long-Term Debt		—			11,080
Other Cash Receipts		1,087			764
Payments of Capital Lease Obligations		(76,236	)		(62,435	)
Repayments of Borrowings Under Revolving Credit Facility		(45,000	)		(60,000	)
Repayments of Long-Term Debt		(6,535	)		—
Payment of Debt Issue/Retirement Costs		(1,948	)		(162	)
Other Cash Payments		(440	)		(427	)
Net Cash Flows – Financing Activities		54,928			(1,180	)
Net Increase in Cash and Cash Equivalents		4,106			14,339
Cash and Cash Equivalents, Beginning of Year		27,718			19,983
Cash and Cash Equivalents, End of Period	$	31,824		$	34,322

See Note 12 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,
	2012			2011
	(Unaudited)
	-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service	$	4,282,596		$	4,222,236
Utility Plant Under Capital Leases		582,669			582,669
Construction Work in Progress		97,978			76,517
Total Utility Plant		4,963,243			4,881,422
Less Accumulated Depreciation and Amortization		(1,776,997	)		(1,753,807	)
Less Accumulated Amortization of Capital Lease Assets		(485,688	)		(476,963	)
Total Utility Plant – Net		2,700,558			2,650,652
Investments and Other Property
Investments in Lease Debt and Equity		36,411			65,829
Other		32,500			32,313
Total Investments and Other Property		68,911			98,142
Current Assets
Cash and Cash Equivalents		31,824			27,718
Accounts Receivable – Customer		86,246			73,612
Unbilled Accounts Receivable		56,616			32,386
Allowance for Doubtful Accounts		(4,272	)		(3,766	)
Accounts Receivable – Due from Affiliates		4,242			4,049
Fuel Inventory		49,954			32,981
Materials and Supplies		74,965			70,749
Regulatory Assets – Current		70,203			71,747
Deferred Income Taxes – Current		26,301			21,678
Investments in Lease Debt		9,593			—
Other		17,025			15,192
Total Current Assets		422,697			346,346
Regulatory and Other Assets
Regulatory Assets – Noncurrent		148,323			157,386
Other Assets		26,454			25,135
Total Regulatory and Other Assets		174,777			182,521
Total Assets	$	3,366,943		$	3,277,661

See Notes to Condensed Consolidated Financial Statements.

(Continued)

12

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2012		December 31, 2011
	(Unaudited)
CAPITALIZATION AND OTHER LIABILITIES	-Thousands of Dollars-
Capitalization
Common Stock Equity	$	845,982	$	824,943
Capital Lease Obligations		276,524		352,720
Long-Term Debt		1,073,878		1,080,373
Total Capitalization		2,196,384		2,258,036
Current Liabilities
Current Obligations Under Capital Leases		88,112		77,482
Borrowing Under Revolving Credit Facility		149,000		10,000
Accounts Payable—Trade		74,734		84,509
Accounts Payable—Due to Affiliates		2,769		4,827
Interest Accrued		13,403		30,877
Accrued Taxes Other than Income Taxes		35,609		32,155
Accrued Employee Expenses		14,785		21,356
Customer Deposits		23,866		23,743
Regulatory Liabilities—Current		22,477		23,702
Derivative Instruments		9,674		9,040
Other		12,004		6,700
Total Current Liabilities		446,433		324,391
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent		272,711		263,225
Regulatory Liabilities—Noncurrent		221,552		200,599
Derivative Instruments		12,973		14,142
Pension and Other Postretirement Benefits		127,292		130,660
Other		89,598		86,608
Total Deferred Credits and Other Liabilities		724,126		695,234
Commitments, Contingencies, and Proposed Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$	3,366,943	$	3,277,661

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 Deficit			Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	(Unaudited) -Thousands of Dollars-
Balances at December 31, 2011	$	888,971	$	(6,357	)	$	(47,627	)	$	(10,044	)	$	824,943
Comprehensive Income
2012 Year-to-Date Net Income							20,449						20,449
Other Comprehensive Income, net of $(294) income taxes										590			590
Total Comprehensive Income													21,039
Balances at June 30, 2012	$	888,971	$	(6,357	)	$	(27,178	)	$	(9,454	)	$	845,982

See Notes to Condensed Consolidated Financial Statements.

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Unaudited

NOTE 1. NATURE OF OPERATIONS AND BASIS OF ACCOUNTING PRESENTATION

UNS Energy Corporation (UNS Energy), formerly UniSource Energy Corporation, is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of June 30, 2012. TEP generates, transmits, and distributes electricity to approximately 405,000 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 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 147,000 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 92,000 retail customers in Mohave and Santa Cruz counties. In July 2011, UNS Electric purchased Black Mountain Generating Station (BMGS) from UED. This transaction did not impact UNS Energy’s consolidated financial statements.

UED currently has no significant remaining assets.

Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of June 30, 2012. See Note 11.

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

The accompanying quarterly financial statements of UNS Energy and TEP are unaudited but reflect all normal recurring accruals and other adjustments which we believe are necessary for a fair presentation of the results for the interim periods presented. These financial statements are presented in accordance with the Securities and Exchange Commission’s interim reporting requirements which do not include all the disclosures required by generally accepted accounting principles (GAAP) in the United States of America for audited annual financial statements. The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. This quarterly report should be reviewed in conjunction with UNS Energy’s and TEP’s 2011 Annual Report on Form 10-K.

Because weather and other factors cause seasonal fluctuations in sales of TEP, UNS Gas, and UNS Electric, quarterly results are not indicative of annual operating results.

To be comparable with the 2012 cash flow statement presentation, UNS Energy reclassified $4 million from Payment of Other Operations and Maintenance Costs to Purchased Energy Costs Paid for transmission costs paid by UNS Electric in 2011. To be comparable with the 2012 balance sheet presentation, UNS Energy reclassified $4 million and TEP reclassified $2 million of 2011 trade receivables with credit balances from Accounts Receivable-Customer to Other Current Liabilities on the balance sheets.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board issued authoritative guidance that eliminated the option to report other comprehensive income in the statement of changes in equity. Rather, an entity must elect to present items of net income and other comprehensive income in one continuous statement or in two separate but consecutive statements. Effective in the first quarter of 2012, we elected to include two separate but consecutive statements.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

We implemented accounting guidance in the first quarter of 2012 which enhances our disclosures regarding unobservable inputs in calculating the fair market value of certain assets and liabilities. The guidance requires additional quantitative and qualitative analysis of inputs when we use significant unobservable inputs to measure the fair value of our derivatives and financial instruments. See Note 9.

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 used by 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.

TEP RATE CASE

In July 2012, TEP filed a general rate case, on a cost-of-service basis, with the ACC requesting a Base Rate increase of approximately 15% to cover a revenue deficiency of $128 million. TEP requested a 5.7% return on a fair value rate base of $2.3 billion. TEP requested a Lost Fixed Cost Recovery (LFCR) mechanism to recover non-fuel costs that would go unrecovered due to lost kilowatt hour sales as a result of implementing the ACC’s Electric Energy Efficiency Standards (Electric EE Standards) and the Renewable Energy Standard. TEP also requested a mechanism, which would be adjusted annually, to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases.

TEP proposed a three-year pilot program allowing for investment in energy efficiency programs to meet the Electric EE Standards in the most cost effective manner. Energy efficiency investments would be considered regulatory assets and amortized over a four-year period. TEP would earn a return on investment and recover the return and amortization expense through the existing Demand Side Management (DSM) surcharge.

UNS GAS RATE CASE

In April 2011, UNS Gas filed a general rate case, on a cost-of-service basis, with the ACC requesting a Base Rate increase of 3.8% to cover a revenue deficiency of $5.6 million.

In April 2012, the ACC approved a Base Rate increase of $2.7 million, an increase of 1.8% over test year Base Rates, as well as a mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the ACC’s Gas Energy Efficiency Standards. UNS Gas expects to recognize less than $0.1 million of revenue under the LFCR in 2012 and 2013. The ACC approved UNS Gas’ 6.26% authorized return on a fair value rate base of $253 million. The new rates became effective on May 1, 2012.

COST RECOVERY MECHANISMS

TEP Purchased Power and Fuel Adjustment Clause

In March 2012, the ACC approved a 0.77 cents per kilowatt-hour (kWh) Purchased Power and Fuel Adjustment Clause (PPFAC) rate, effective April 2012 and approved the elimination of the fixed Competition Transition Charge credit to the PPFAC of 0.53 cents per kWh. As a result of the new PPFAC rate, in the first quarter of 2012, TEP moved the entire $15 million of under-collected costs from Regulatory Assets – Noncurrent to Regulatory Assets – Current on the balance sheets. At June 30, 2012, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $54 million, an increase of $5 million from December 31, 2011.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

UNS Gas Purchased Gas Adjustor

In May 2012, the ACC approved a Purchased Gas Adjustor (PGA) temporary credit of 4.5 cents per therm for the period of May 2012 through April 2014. At June 30, 2012, the PGA bank balance was over-collected by $17 million on a billed-to-customer basis, an increase of $9 million from December 31, 2011.

UNS Electric PPFAC

At June 30, 2012, UNS Electric had under-collected fuel and purchased power costs on a billed-to-customer basis of $8 million, a decrease of $3 million from December 31, 2011.

ELECTRIC ENERGY EFFICIENCY STANDARDS

In May 2012, TEP filed a modification to its proposed 2011-2012 Energy Efficiency Implementation Plan with the ACC. The proposal includes a request for a performance incentive for 2012 ranging from approximately $3 million to $4 million and the collection of the performance incentive over a period from October 1, 2012 to December 31, 2012. Hearings before an administrative law judge on this matter were completed in July 2012. TEP cannot predict when the administrative law judge will issue a recommendation or when the ACC will issue a final order in this matter.

NOTE 3. BUSINESS SEGMENTS

We have three reportable segments that are determined based on the way we organize our operations and evaluate performance:

(1) TEP, a regulated electric utility business, is our largest subsidiary;

(2) UNS Gas is a regulated gas distribution utility business; and

(3) UNS Electric is a regulated electric utility business.

Results for the UNS Energy and UES holding companies, Millennium, and UED are included in Other below.

We accounted for UNS Electric’s purchase of BMGS in July 2011 in accordance with accounting rules related to the transfer of a business held under common control. UNS Electric’s net income increased by $1 million for the three months ended June 30, 2011, and $2 million for the six months ended June 30, 2011. The increases were offset by reconciling adjustments and had no impact on UNS Energy’s consolidated financial statements.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

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

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Other		Reconciling Adjustments			UNS Energy Consolidated
Income Statement	-Millions of Dollars-
Three Months Ended June 30, 2012:
Operating Revenues – External	$	295	$	21	$	51	$	—	$	—		$	367
Operating Revenues – Intersegment(1)		4		1		—		5		(10	)		—
Income Before Income Taxes		36		—		7		—		—			43
Net Income		22		—		4		—		—			26
Three Months Ended June 30, 2011:
Operating Revenues – External	$	292	$	25	$	52	$	1	$	—		$	370
Operating Revenues – Intersegment(1)		3		1		1		7		(12	)		—
Income Before Income Taxes		40		1		6		—		(1	)		46
Net Income		25		—		4		1		(1	)		29

	Reportable Segments
	TEP		UNS Gas		UNS Electric		Other			Reconciling Adjustments			UNS Energy Consolidated
Income Statement	-Millions of Dollars-
Six Months Ended June 30, 2012:
Operating Revenues – External	$	515	$	73	$	98	$	—		$	—		$	686
Operating Revenues – Intersegment(1)		8		2		1		9			(20	)		—
Income (Loss) Before Income Taxes		33		9		12		(1	)		—			53
Net Income		20		5		7		1			—			33
Six Months Ended June 30, 2011:
Operating Revenues – External	$	528	$	84	$	102	$	—		$	—		$	714
Operating Revenues – Intersegment(1)		7		1		1		14			(23	)		—
Income Before Income Taxes		48		11		12		—			(4	)		67
Net Income		30		7		7		—			(2	)		42

⁽¹⁾  TEP includes in Operating Revenues – Intersegment: 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 Dow Jones Four Corners Daily Index prices.

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

NOTE 4. DEBT AND CREDIT FACILITIES

We summarized below the significant changes to our debt from those reported in our 2011 Annual Report on Form 10-K.

UNS ENERGY DEBT – CONVERTIBLE SENIOR NOTES

In 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due in 2035. UNS Energy converted or redeemed the entire $150 million Convertible Senior Notes outstanding. Holders of the Convertible Senior Notes had the option of converting their interests to Common Stock at a conversion rate applicable at the time of each notice of redemption or receiving par plus accrued interest for the Convertible Senior Notes. In the first quarter of 2012, holders of approximately $73 million of the Convertible Senior Notes converted their interests into approximately 2.1 million shares of Common Stock and $2 million was redeemed for cash. In the second quarter of 2012, holders of approximately $74 million of Convertible Senior Notes converted their interests into approximately 2.2 million shares and $1 million was redeemed for cash.

UNS ENERGY CREDIT AGREEMENT

UNS Energy had $83 million in outstanding borrowings at June 30, 2012, and $57 million in outstanding borrowings at December 31, 2011, under its revolving credit facility. We have included the revolver borrowings in Long-Term Debt on the balance sheets as UNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of July 18, 2012, UNS Energy had $83 million in outstanding borrowings under its revolving credit facility.

TEP TAX-EXEMPT BONDS

In March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. TEP’s $8 million payment to the trustee was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized approximately $2 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt through March 2030, the term of the bonds.

In June 2012, the Industrial Development Authority of Pima County, Arizona issued approximately $16 million of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds together with $0.4 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $16 million of outstanding unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. As the original debt was legally extinguished, the debt issuance in June 2012 had no impact on TEP’s debt outstanding at June 30, 2012. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized less than $0.5 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt through June 2030, the term of the bonds.

TEP CREDIT AGREEMENT

TEP had $149 million in borrowings outstanding and $1 million in letters of credit issued under its revolving credit facility at June 30, 2012. At December 31, 2011, TEP had $10 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility. TEP included the revolver borrowings in Current Liabilities on the balance sheets. The outstanding letters of credit are off-balance sheet obligations of TEP. As of July 18, 2012, TEP had $127 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility.

UNS GAS/UNS ELECTRIC CREDIT AGREEMENT

UNS Electric had $1 million at June 30, 2012, and $6 million at December 31, 2011, in outstanding letters of credit under the UNS Gas/UNS Electric Credit Agreement, which are not shown on the balance sheets.

COVENANT COMPLIANCE

As of June 30, 2012, UNS Energy and its subsidiaries were in compliance with the terms of their respective loan and credit agreements.

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

NOTE 5. INCOME TAXES

The differences between the income tax expense and the amount obtained by multiplying pre-tax income by the U.S. statutory federal income tax rate of 35% are as follows:

	Three Months Ended June 30,
	UNS Energy					TEP
	2012		2011			2012		2011
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	15	$	16		$	13	$	14
State Income Tax Expense, Net of Federal Deduction		2		2			1		2
Federal/State Tax Credits		—		(1	)		—		(1	)
Total Federal and State Income Tax Expense	$	17	$	17		$	14	$	15

	Six Months Ended June 30,
	UNS Energy						TEP
	2012			2011			2012			2011
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	19		$	24		$	11		$	17
State Income Tax Expense, Net of Federal Deduction		2			3			2			3
Federal/State Tax Credits		—			(1	)		—			(1	)
Cash Surrender Value of Life Insurance		(1	)		(1	)		(1	)		(1	)
Total Federal and State Income Tax Expense	$	20		$	25		$	12		$	18

The Internal Revenue Service completed its audit of the 2008 tax return in March 2012 with no change to the balance of unrecognized tax benefits.

NOTE 6. COMMITMENTS, CONTINGENCIES, AND PROPOSED ENVIRONMENTAL MATTERS

In addition to those reported in our 2011 Annual Report on Form 10-K, we entered into the following new long-term commitments.

TEP COMMITMENTS

In February 2012, TEP entered into a long-term agreement for information technology services. TEP is obligated to pay $2 million per year over the next three years.

TEP entered into new forward purchase power commitments that will settle in June 2013 through September 2013 at fixed prices per megawatt-hour (MWh). TEP’s minimum payment obligation for these purchases is $5 million.

UNS GAS COMMITMENTS

UNS Gas entered into new forward fuel commitments that settle through June 2015 at fixed prices per million British thermal unit (MMBtu). UNS Gas’ minimum payment obligations for these purchases are $1 million in 2013, $3 million in 2014, and $1 million in 2015.

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

UNS ELECTRIC COMMITMENTS

UNS Electric 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, 2012, UNS Electric’s estimated minimum payment obligations for these purchases are $4 million in 2013 and $8 million in 2014.

TEP CONTINGENCIES

Claim Related to Springerville Generating Station

In July 2012, Springerville Unit 3 experienced an unplanned outage. As a result of the outage, in July 2012, TEP recorded a pre-tax loss of $2 million as TEP does not expect to meet certain availability requirements under the terms of TEP’s operating agreement with Tri-State.

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 has 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.

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.

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 at June 30, 2012, was $15 million and at December 31, 2011, was $13 million.

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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.

In June 2012, the participants at San Juan executed a Trust Reclamation Agreement requiring each participant to individually establish a trust, and fund that trust, based on the participant’s share of the estimated final mine reclamation costs. The trust must remain in effect through completion of final mine reclamation activities currently projected to be 2050. TEP must have a balance in its trust sufficient to fund its share of the funding target curve in any given year throughout the life of the Trust Reclamation Agreement. TEP expects to establish and initially fund its trust with $1 million in the third quarter of 2012.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. UNS Electric’s participation in this project was initiated in response to an order by the ACC to improve the reliability of electric service in Nogales. That order was issued before UNS Energy purchased the electric system in Nogales and surrounding Santa Cruz County in August 2003.

In 2002, the ACC authorized construction of the proposed 345-kV line along a route identified as the Western Corridor subject to a number of conditions, including the issuance of all required permits from state and federal agencies. The U.S. Forest Service subsequently expressed its preference for a different route in its final Environmental Impact Statement for the project. If a decision was made to pursue an alternative route, approvals would be needed from the ACC, the Department of Energy, the U.S. Forest Service, the Bureau of Land Management, and the International Boundary and Water Commission. As of June 30, 2012, and December 31, 2011, TEP had capitalized $11 million related to the project, including $2 million to secure land and land rights.

Based on the cost of the proposed 345-kV line, and difficulty in reaching agreement with the Forest Service on a path for the line, TEP proposed to abandon this project in its general rate case filed with the ACC in July 2012. TEP requested rate recovery of the $9 million of non-land related costs over a three-year amortization period. TEP believes cost recovery is probable for the $9 million of prudent and reasonably incurred costs related to the project as a consequence of the ACC’s requirement for the 60-mile transmission line to the Nogales area.

Resolution of Contingencies

In April 2010, the Sierra Club filed a citizens’ suit under the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA) in the U.S. District Court for the District of New Mexico against Public Service Company of New Mexico (PNM), as operator of San Juan; PNM’s parent PNM Resources, Inc. (PNMR); SJCC; and SJCC’s parent BHP Minerals International Inc. (BHP). The Sierra Club alleged in the suit that certain activities at San Juan and the San Juan mine associated with the treatment, storage, and disposal of coal and Coal Combustion Residuals (CCRs), primarily coal ash, are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCRs at the mine constitutes “open dumping” in violation of RCRA. The RCRA claims were asserted against PNM, PNMR, SJCC, and BHP. The suit also included claims under SMCRA which were directed only against SJCC and BHP. The suit sought the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCRs at the mine or to cease placement of CCRs at the mine; the imposition of civil penalties; and attorney’s fees and costs. In March 2012, the parties settled the case. The settlement was approved by the Court.

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

TEP owns 50% of San Juan Units 1 and 2, which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of the settlement of the San Juan claims. TEP recorded less than $1 million for its share of the costs to fund environmental projects and Sierra Club attorney and expert fees required by the settlement, substantially all of which was recorded in 2011. In addition, TEP expects to pay $1 million for its share of construction costs for a new groundwater recovery system adjacent to San Juan and other environmental projects required by the settlement.

San Juan Mine Fire

In September 2011, a fire at the underground mine that provides coal to San Juan caused mining operations to shut down. The mine resumed production in June 2012.

The mine fire did not have a material effect on our financial condition, results of operations, or cash flows due to the use of on-hand inventory of previously mined coal and the low market price of wholesale power during the closure.

PROPOSED ENVIRONMENTAL MATTERS

TEP’s generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), and other emissions released into the atmosphere. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its electric generating facilities. Compliance with these changes may reduce operating efficiency.

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 December 2011, the EPA issued the final rules establishing the standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units.

Navajo

Based on the EPA’s final standards, mercury and particulate emission control equipment may be required at Navajo by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and approximately $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.

Springerville Generating Station

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

San Juan

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s final standards.

Sundt Generating Station

TEP does not anticipate that the final EPA standards will have a material impact on capital expenditures at Sundt Generating Station.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

Four Corners

Based on the EPA’s final standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated capital cost of this equipment is less than $1 million. The annual operating cost associated with the mercury emission control equipment is expected to be less than $1 million.

Regional Haze Rules

The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA for approval. Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions. The EPA oversees regional haze planning for these facilities.

Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations, and other business considerations could jeopardize the economic viability of the Navajo, San Juan, and Four Corners facilities or the ability of individual participants to meet their obligations and maintain participation in these facilities. TEP cannot predict the ultimate outcome of these matters.

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the National Renewable Energy Laboratory in partnership with the Department of the Interior and the Department of Energy. The report addresses potential energy, environmental, and economic issues related to compliance with the regional haze rule. The report was submitted to the EPA in January 2012. A final BART rule is expected later in 2012. If the EPA determines that Selective Catalytic Reduction (SCR) technology is required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the generating facility’s particulate emissions necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital expenditure for the required baghouses would be approximately $43 million. The cost of required pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.

San Juan

In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions. TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180 million and $200 million.

In 2011, PNM filed a petition for review of and a motion to stay the FIP with the Tenth Circuit U. S. Court of Appeals (Circuit Court). In addition, PNM 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 the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and the EPA. In March 2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. In July 2012, the EPA issued a 90-day stay to allow the State of New Mexico, the EPA, PNM, and other interested parties to evaluate alternatives to the final FIP.

Several environmental groups were granted permission to join in opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted permission to join in opposition to that appeal. In April 2012, PNM, the State of New Mexico, and WildEarth Guardians individually filed briefs on the merits in their respective Circuit Court appeals. TEP cannot predict the ultimate outcome of this matter.

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

Four Corners

In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that would require the installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the capital costs to install SCR is approximately $35 million.

Sundt Generating Station

The EPA is required to issue a proposal regarding unaddressed state regional haze compliance issues in December 2012. The proposal may, among other things, include a determination regarding whether Sundt Unit 4 could be regulated under certain regional haze provisions.

Springerville

Regional haze regulations requiring emission control upgrades are not applicable to Springerville at this time and are not likely to impact Springerville operations until 2018 or later.

NOTE 7. EMPLOYEE BENEFIT PLANS

The components of UNS Energy’s net periodic benefit plan cost are as follows:

	Three Months Ended June 30,
	Pension Benefits						Other  Postretirement Benefits
	2012			2011			2012		2011
	-Millions of Dollars-
Components of Net Periodic Benefit Plan Cost
Service Cost	$	2		$	2		$	1	$	1
Interest Cost		4			4			1		1
Expected Return on Plan Assets		(4	)		(4	)		—		—
Amortization of Net Loss		2			2			—		—
Net Periodic Benefit Plan Cost	$	4		$	4		$	2	$	2

The table above includes pension benefit plan costs of $0.5 million and other postretirement benefit plan costs of less than $0.1 million for UNS Gas and UNS Electric.

	Six Months Ended June 30,
	Pension Benefits						Other  Postretirement Benefits
	2012			2011			2012			2011
	-Millions of Dollars-
Components of Net Periodic Benefit Plan Cost
Service Cost	$	5		$	5		$	2		$	2
Interest Cost		8			8			2			2
Expected Return on Plan Assets		(9	)		(8	)		—			—
Amortization of Prior Service Costs		—			—			(1	)		(1	)
Amortization of Net Loss		4			3			—			—
Net Periodic Benefit Plan Cost	$	8		$	8		$	3		$	3

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

The table above includes pension benefit plan costs of $1 million and other postretirement benefit plan costs of less than $0.1 million for UNS Gas and UNS Electric.

NOTE 8. SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS AND PERFORMANCE SHARES

Restricted Stock Units

In May 2012, the UNS Energy Compensation Committee granted 15,303 restricted stock units to non-employee directors at a grant date fair value of $35.94 per share. The restricted stock units vest in one year or immediately upon death, disability, or retirement. Compensation expense equal to the fair market value on the grant date is recognized over the vesting period. Fully vested but undistributed stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. In the January following the year the person is no longer a director, Common Stock shares will be issued for the vested stock units.

Performance Shares

In March 2012, the UNS Energy Compensation Committee granted 80,140 performance share awards to upper management. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $32.71 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 Edison Electric Institute Index during the performance period of January 1, 2012 through December 31, 2014. The remaining half had a grant date fair value of $36.40 per share and will be paid out in Common Stock based on cumulative net income for the three-year period ended December 31, 2014. 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 are eligible for dividend equivalents during the performance period.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded less than $1 million of share-based compensation expense for each of the three months ended June 30, 2012 and June 30, 2011. For the six months ended June 30, 2012, UNS Energy and TEP recorded share-based compensation expense of $1 million. For the six months ended June 30, 2011, UNS Energy recorded share-based compensation expense of $2 million, $1 million of which related to TEP.

At June 30, 2012, the total unrecognized compensation cost related to non-vested share-based compensation was $4 million, which will be recorded as compensation expense over the remaining vesting periods through December 2014. At June 30, 2012, one million shares were awarded but not yet issued, including target performance based shares, under the share-based compensation plans.

NOTE 9. FAIR VALUE MEASUREMENTS

We categorize our assets and liabilities at fair value into the three-level hierarchy based on inputs used to determine the fair value measurement. 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.

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

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
	Level 1		Level 2			Level 3			Total
	June 30, 2012 -Millions of Dollars-
Assets
Cash Equivalents(1)	$	27	$	—		$	—		$	27
Rabbi Trust Investments to Support the Deferred Compensation and Supplemental Executive Retirement Plans (SERP) (2)		—		18			—			18
Energy Contracts(3)		—		3			10			13
Total Assets		27		21			10			58
Liabilities
Energy Contracts(3)		—		(18	)		(17	)		(35	)
Interest Rate Swaps(4)		—		(11	)		—			(11	)
Total Liabilities		—		(29	)		(17	)		(46	)
Net Total Assets and (Liabilities)	$	27	$	(8	)	$	(7	)	$	12
	UNS Energy
	Level 1		Level 2			Level 3			Total
	December 31, 2011 -Millions of Dollars-
Assets
Cash Equivalents(1)	$	23	$	—		$	—		$	23
Rabbi Trust Investments to Support the Deferred Compensation and SERP(2)		—		16			—			16
Energy Contracts(3)		—		—			14			14
Total Assets		23		16			14			53
Liabilities
Energy Contracts(3)		—		(21	)		(24	)		(45	)
Interest Rate Swaps(4)		—		(12	)		—			(12	)
Total Liabilities		—		(33	)		(24	)		(57	)
Net Total Assets and (Liabilities)	$	23	$	(17	)	$	(10	)	$	(4	)

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

	TEP
	Level 1		Level 2			Level 3			Total
	June 30, 2012 -Millions of Dollars-
Assets
Cash Equivalents(1)	$	7	$	—		$	—		$	7
Rabbi Trust Investments to Support the Deferred Compensation and SERP(2)		—		18			—			18
Energy Contracts(3)		—		2			2			4
Total Assets		7		20			2			29
Liabilities
Energy Contracts(3)		—		(9	)		(3	)		(12	)
Interest Rate Swaps(4)		—		(11	)		—			(11	)
Total Liabilities		—		(20	)		(3	)		(23	)
Net Total Assets and (Liabilities)	$	7	$	—		$	(1	)	$	6
	TEP
	Level 1		Level 2			Level 3			Total
	December 31, 2011 -Millions of Dollars-
Assets
Cash Equivalents(1)	$	8	$	—		$	—		$	8
Rabbi Trust Investments to Support the Deferred Compensation and SERP(2)		—		16			—			16
Energy Contracts(3)		—		—			3			3
Total Assets		8		16			3			27
Liabilities
Energy Contracts(3)		—		(9	)		(3	)		(12	)
Interest Rate Swaps(4)		—		(11	)		—			(11	)
Total Liabilities		—		(20	)		(3	)		(23	)
Net Total Assets and (Liabilities)	$	8	$	(4	)	$	—		$	4

⁽¹⁾  Cash Equivalents are based on observable market prices and include the fair value of money market funds and certificates of deposit. These amounts are included in Cash and Cash Equivalents and Investments and Other Property—Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts held in mutual and money market funds related to deferred compensation and SERP benefits. The valuation is based on 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 balance sheets. The valuation techniques are described below. See Note 13.

⁽⁴⁾  Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate 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.

ENERGY CONTRACTS

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.

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, and 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.

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

	Fair Value at June 30, 2012					Range of
	Assets		Liabilities			Unobservable Input
	-Millions of Dollars-
Forward Contracts(1)	$	8	$	(17	)
Valuation Technique: Market approach
Unobservable Input:
Market price per MWh						$	21.25		-	$	56.65
Option Contracts(2)		2		—
Valuation Technique: Option model
Unobservable Inputs:
Market Price per MWh						$	29.75		-	$	47.02
Power Volatility							26.18	%	-		93.45	%
Market Price per MMBtu						$	2.60		-	$	3.83
Gas Volatility							30.20	%	-		56.93	%
Level 3 Energy Contracts	$	10	$	(17	)

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

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

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

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, 2012
	UNS Energy			TEP
	-Millions of Dollars-
Balance as of March 31, 2012	$	(13	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		2			(1	)
Settlements		4			—
Balance as of 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-
Balance as of December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(4	)		—
Settlements		7			(1	)
Balance as of 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	)	$	—
	Three Months Ended June 30, 2011
	UNS Energy			TEP
	-Millions of Dollars-
Balance as of March 31, 2011	$	(11	)	$	1
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(1	)		—
Settlements		3			—
Balance as of June 30, 2011	$	(9	)	$	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	)	$	—

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

	Six Months Ended June 30, 2011
	UNS Energy			TEP
	-Millions of Dollars-
Balance as of December 31, 2010	$	(10	)	$	1
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(3	)		1
Other Comprehensive Income		(1	)		(1	)
Settlements		5			—
Balance as of June 30, 2011	$	(9	)	$	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	)	$	—

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 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.

31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

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

		June 30, 2012				December 31, 2011
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		-Millions of Dollars-
Assets:
TEP Investment in Lease Debt	Level 2	$	10	$	10	$	29	$	29
TEP Investment in Lease Equity	Level 3		36		23		37		21
Liabilities:
Long-Term Debt
UNS Energy	Level 2		1,387		1,432		1,517		1,543
TEP	Level 2		1,074		1,083		1,080		1,061

TEP intends to hold the $10 million investment in Springerville Lease Debt to maturity. This investment is stated at amortized cost, which means the purchase cost has been adjusted for the amortization of the premium and discount to maturity.

NOTE 10. UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options, contingently issuable shares under equity-based awards, or common shares that would result from the conversion of Convertible Senior Notes. 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 shows the effects of potentially dilutive Common Stock on the weighted average number of shares:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	-Thousands of Dollars-
Numerator:
Net Income	$	26,273	$	28,604	$	32,749	$	42,076
Income from Assumed Conversion of Convertible Senior Notes		237		1,097		1,100		2,195
Adjusted Numerator	$	26,510	$	29,701	$	33,849	$	44,271
	-Thousands of Shares-
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued		40,322		36,757		39,107		36,676
Fully Vested Deferred Stock Units		149		127		144		122
Participating Securities		—		66		—		71
Total Weighted Average Shares of Common Stock Outstanding and Participating Securities – Basic		40,471		36,950		39,251		36,869
Effect of Dilutive Securities:
Convertible Senior Notes		909		4,267		2,125		4,254
Options and Stock Issuable Under Share-Based Compensation Plans		250		338		270		354
Total Shares – Diluted		41,630		41,555		41,646		41,477

32

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

The following table shows the number of stock options excluded from the diluted EPS computation because the stock options’ exercise price was greater than the average market price of the Common Stock:

	Three Months Ended June  30,				Six Months Ended June  30,
	2012		2011		2012		2011
	-Thousands of Shares-
Stock Options Excluded from the Diluted EPS Computation		101		158		101		163

In the first half of 2012, the entire balance of Convertible Senior Notes was converted to Common Shares or redeemed for cash. See Note 4.

NOTE 11. MILLENNIUM INVESTMENTS

In 2009, Millennium sold an equity investment and recorded a $6 million gain on the sale. Millennium received an upfront payment of $5 million in 2009 and a $15 million, three-year, 6% secured promissory note with a maturity date of June 2012. In June 2012, at the request of the borrower, Millennium agreed to change the payment provisions and maturity date of the note. The remaining terms of the note, including provisions securing the payment of the loan amount, remain unchanged. Based on the short-term nature of the note and the fair value of the collateral, management expects the carrying value of the note to be fully realizable. Under the modified payment terms, Millennium received principal payments of $5 million and a $0.25 million amendment fee in June 2012, $2.5 million in July 2012, and is entitled to receive monthly payments of $2.5 million plus accrued interest until the outstanding principal amount is paid in full on October 1, 2012.

33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

NOTE 12. SUPPLEMENTAL CASH FLOW INFORMATION

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

	UNS Energy
	Six Months Ended June 30,
	2012			2011
	-Thousands of Dollars-
Net Income	$	32,749		$	42,076
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense		70,174			66,100
Amortization Expense		17,776			14,631
Depreciation and Amortization Recorded to Fuel and Other Operations and Maintenance		3,234			2,879
Amortization of Deferred Debt-Related Costs Included in Interest Expense		1,545			2,070
Provision for Retail Customer Bad Debts		1,571			1,289
Use of Renewable Energy Credits for Compliance		3,055			3,623
Deferred Income Taxes		17,397			32,469
Pension and Postretirement Expense		10,927			10,605
Pension and Postretirement Funding		(10,957	)		(8,932	)
Share-Based Compensation Expense		1,170			1,704
Allowance for Equity Funds Used During Construction		(1,920	)		(2,737	)
Competition Transition Charge Revenue Refunded		—			(15,112	)
Increase (Decrease) to Reflect PPFAC/PGA Recovery		11,654			(1,599	)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(19,547	)		(11,279	)
Materials and Fuel Inventory		(14,169	)		(681	)
Accounts Payable		(10,022	)		17,302
Income Taxes		2,062			(8,273	)
Interest Accrued		(7,839	)		(1,360	)
Taxes Other Than Income Taxes		952			453
Other		2,732			3,861
Net Cash Flows – Operating Activities	$	112,544		$	149,089

34

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

	TEP
	Six Months Ended June 30,
	2012			2011
	-Thousands of Dollars-
Net Income	$	20,449		$	29,861
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense		55,012			51,583
Amortization Expense		19,620			16,484
Depreciation and Amortization Recorded to Fuel and Other Operations and Maintenance		2,506			2,070
Amortization of Deferred Debt-Related Costs Included in Interest Expense		1,072			1,290
Provision for Retail Customer Bad Debts		1,104			905
Use of Renewable Energy Credits for Compliance		2,622			3,355
Deferred Income Taxes		10,810			24,163
Pension and Postretirement Expense		9,644			9,410
Pension and Postretirement Funding		(9,856	)		(8,168	)
Share-Based Compensation Expense		923			1,330
Allowance for Equity Funds Used During Construction		(1,646	)		(2,392	)
Competition Transition Charge Revenue Refunded		—			(15,112	)
Increase (Decrease) to Reflect PPFAC Recovery		5,125			(6,262	)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(34,287	)		(23,662	)
Materials and Fuel Inventory		(13,761	)		329
Accounts Payable		258			24,769
Income Taxes		1,769			(8,292	)
Interest Accrued		(6,805	)		(1,465	)
Taxes Other Than Income Taxes		3,454			2,822
Other		(1,507	)		3,224
Net Cash Flows – Operating Activities	$	66,506		$	106,242

Non-Cash Transactions

In the first six months of 2012, UNS Energy converted $147 million of the $150 million Convertible Senior Notes and TEP redeemed $193 million of the $200 million tax-exempt bonds resulting in non-cash transactions. See Note 4.

NOTE 13. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

RISKS AND OVERVIEW

We are exposed to energy price risk associated with our gas and purchased power requirements, volumetric risk associated with our seasonal load, and operational risk associated with our generating facilities, transmission, and transportation systems. 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; ensuring we can meet load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Notes 2 and 9.

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.

35

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

DERIVATIVES POLICY

There have been no significant changes to our derivative instrument or credit risk policies as described in our Annual Report on Form 10-K for the year ended December 31, 2011.

FINANCIAL IMPACT OF DERIVATIVES

Cash Flow Hedges

At June 30, 2012 and December 31, 2011, UNS Energy and TEP had liabilities related to cash flow hedges of $14 million. The after-tax unrealized gains (losses) on derivative activities and amounts reclassified to earnings are reported in the statements of other comprehensive income.

Regulatory Treatment of Commodity Derivatives

We disclose 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 statements of other comprehensive income or in the income statement, as shown in the following table:

	UNS Energy						TEP
	Three Months Ended June 30,
	2012			2011			2012			2011
	-Millions of Dollars-
Decrease to Regulatory Assets	$	(17	)	$	(3	)	$	(6	)	$	—

	UNS Energy						TEP
	Six Months Ended June 30,
	2012			2011			2012			2011
	-Millions of Dollars-
Decrease to Regulatory Assets	$	(9	)	$	(10	)	$	(1	)	$	(2	)

The fair value of derivative assets and liabilities were as follows:

	UNS Energy						TEP
	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	-Millions of Dollars-
Assets	$	13		$	14		$	4		$	3
Liabilities		(33	)		(43	)		(9	)		(9	)
Net Liabilities	$	(20	)	$	(29	)	$	(5	)	$	(6	)

36

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) – Unaudited

The realized losses on settled gas swaps that are fully recoverable through the PPFAC or PGA were as follows:

	UNS Energy				TEP
	Three Months Ended June 30,
	2012		2011		2012		2011
	-Millions of Dollars-
Realized Losses on Settled Gas Swaps	$	7	$	3	$	4	$	2

	UNS Energy				TEP
	Six Months Ended June 30,
	2012		2011		2012		2011
	-Millions of Dollars-
Realized Losses on Settled Gas Swaps	$	14	$	9	$	6	$	2

At June 30, 2012, UNS Energy and TEP had contracts that will settle through the third quarter of 2015.

Other Commodity Derivatives

The settlement of forward purchased power and sales contracts that do not result in physical delivery were reflected in the financial statements of UNS Energy and TEP as follows:

	Three Months Ended June  30,						Six Months Ended June  30,
	2012			2011			2012			2011
	-Millions of Dollars-
Recorded in Wholesale Sales:
Forward Power Sales	$	—		$	2		$	1		$	3
Forward Power Purchases		(1	)		(3	)		(2	)		(4	)
Total Sales and Purchases Not Resulting in Physical Delivery	$	(1	)	$	(1	)	$	(1	)	$	(1	)

DERIVATIVE VOLUMES

At June 30, 2012, UNS Energy had gas swaps totaling 24,936 billion British thermal units (GBtu) and power contracts totaling 2,660 gigawatt-hours (GWh), while TEP had gas swaps totaling 15,488 GBtu and power contracts totaling 854 GWh. At December 31, 2011, UNS Energy had gas swaps totaling 14,856 GBtu and power contracts totaling 3,147 GWh, while TEP had gas swaps totaling 6,855 GBtu and power contracts totaling 815 GWh. We account for gas swaps and power contracts as derivatives.

CREDIT RISK ADJUSTMENT

When the fair value of our derivative contracts is reflected as an asset, the counterparty owes us and this creates credit risk. We also consider the impact of our own credit risk on instruments that are in a net liability position. The impact of counterparty credit risk and our own credit risk on the fair value of derivative asset contracts was less than $0.5 million at June 30, 2012 and at December 31, 2011.

37

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded) – Unaudited

CONCENTRATION OF CREDIT RISK

The following table shows the sum of the fair value of all derivative instruments under contracts with credit risk-related contingent features that are in a net liability position at June 30, 2012. Since credit risk-related contingent features were not triggered in the periods presented, UNS Energy and TEP have not posted cash collateral.

	UNS Energy		TEP
	June 30, 2012
	-Millions of Dollars-
Net Liability Position	$	54	$	27
Letters of Credit		2		1
Additional Collateral to Post if Contingent Features Triggered		54		27

As of June 30, 2012, TEP had $13 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities, of which three counterparties individually composed greater than 10% of the total credit exposure. UNS Electric had less than $1 million of such credit exposure related to its supply and hedging contracts. At June 30, 2012, UNS Gas had no exposure to other counterparties’ creditworthiness.

NOTE 14. REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The UNS Energy and TEP condensed consolidated financial statements as of June 30, 2012, and for the three and six month periods ended June 30, 2012 and 2011, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their reports (dated July 30, 2012) 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.

38

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 Corporation (UNS Energy), formerly known as UniSource Energy Corporation, and its three primary business segments. It includes the following:

• outlook and strategies;

• operating results during the second quarter and six month period ended June 30, 2012 compared with the same periods in 2011;

• 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 Tucson Electric Power Company’s (TEP) 2011 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 month periods ended June 30, 2012 and 2011. Management’s Discussion and Analysis explains the differences between periods for specific line items of the Condensed Consolidated Financial Statements.

UNS ENERGY CONSOLIDATED

OVERVIEW OF CONSOLIDATED BUSINESS

UNS Energy is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of June 30, 2012. TEP generates, transmits, and distributes electricity to approximately 405,000 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 U.S. In addition, TEP operates 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 147,000 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 92,000 retail customers in Mohave and Santa Cruz counties. In July 2011, UNS Electric purchased Black Mountain Generating Station (BMGS) from UED. This transaction did not impact UNS Energy’s consolidated financial statements.

UED currently has no significant assets.

Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of June 30, 2012.

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

39

OUTLOOK AND STRATEGIES

Our financial prospects and outlook are affected by many factors including: the 2008 TEP Rate Order that freezes Base Rates through 2012; national and regional economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:

• Obtain ACC approval of a retail Base Rate increase and new retail rate design for TEP, effective no later than August 1, 2013, that: (i) provides adequate revenues to cover the rising cost of serving TEP’s customers; (ii) aligns TEP’s retail rates with Arizona’s requirements for energy efficiency and distributed generation; and (iii) allows TEP an opportunity to earn a fair return on its investment.

• Focus on our core utility businesses through operational excellence, investing in utility rate base, emphasizing customer satisfaction, maintaining a strong community presence, and achieving constructive regulatory outcomes.

• Develop strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas (GHG) emissions. We are evaluating TEP’s existing mix of generation resources and defining steps to achieve environmental objectives that provide an appropriate return on investment and are consistent with earnings growth.

• Expand 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.

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,
	2012		2011		2012		2011
	-Millions of Dollars-
TEP	$	22	$	25	$	20	$	30
UNS Gas		—		—		5		7
UNS Electric		4		4		7		7
Other Non-Reportable Segments and Adjustments (1)		—		—		1		(2	)
Consolidated Net Income	$	26	$	29	$	33	$	42

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

Executive Overview

Second Quarter of 2012 Compared with the Second Quarter of 2011

TEP

TEP reported net income of $22 million in the second quarter of 2012 compared with net income of $25 million in the second quarter of 2011. The decrease in net income in the second quarter of 2012 is attributable to: a $4 million decrease in long-term wholesale margin revenues; a $4 million increase in depreciation and amortization expense; and a $3 million increase in Base Operations and Maintenance (O&M) expense; partially offset by a $7 million increase in retail margin revenue. See Tucson Electric Power Company, Results of Operations, below for more information.

40

UNS Gas and UNS Electric

UNS Gas reported no net income in the second quarters of 2012 and 2011. See UNS Gas, Results of Operations, below for more information.

UNS Electric reported net income of $4 million in the second quarters of 2012 and 2011. See UNS Electric, Results of Operations, below for more information.

Other Non-Reportable Segments

The results reported for Other Non-Reportable Segments include UNS Energy parent company expenses, Millennium, UED, and intercompany eliminations. See Other Non-Reportable Segments, Results of Operations, below, for more information.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011

TEP

TEP reported net income of $20 million in the first six months of 2012 compared with net income of $30 million in the same period last year. The decrease in net income is attributable to: a $9 million decrease in long-term wholesale margin revenues; a $7 million increase in depreciation and amortization expense; and a $1 million increase in Base O&M expense; partially offset by a $4 million increase in retail margin revenue. See Tucson Electric Power Company, Results of Operations, below for more information.

UNS Gas and UNS Electric

UNS Gas reported net income of $5 million in the first six months of 2012 compared with net income of $7 million in the same period last year. See UNS Gas, Results of Operations, below for more information.

UNS Electric reported net income of $7 million in the first six months of 2012 and 2011. See UNS Electric, Results of Operations, below for more information.

41

Other Operations and Maintenance Expense

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

	2012		2011
	-Millions of Dollars-
Three Months Ended June 30,
UNS Energy Base O&M (Non-GAAP)(1)	$	68	$	65
Reimbursed Expenses Related to Springerville Units 3 and 4		13		16
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs		10		9
Total UNS Energy Other O&M (GAAP)	$	91	$	90
Six Months Ended June 30,
UNS Energy Base O&M (Non-GAAP)(1)	$	137	$	136
Reimbursed Expenses Related to Springerville Units 3 and 4		27		32
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs		21		23
Total UNS Energy Other O&M (GAAP)	$	185	$	191

⁽¹⁾ Base O&M, a non-GAAP financial measure, should not be considered as an alternative to Other 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.

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

Balances as of July 18, 2012	Cash and  Cash Equivalents			Borrowings under Revolving Credit Facility(1)		Amount Available under Revolving Credit Facility
	-Millions of Dollars-
UNS Energy Stand-Alone	$	9		$	83	$	42
TEP		23			128		72
UNS Gas		43			—		70	(2)
UNS Electric		22			1		69	(2)
Other		4	(3)		N/A		N/A
Total	$	101

⁽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 no dividends from its subsidiaries during the second quarters of 2012 or 2011. In July 2012, Millennium paid a $9 million dividend to UNS Energy.

42

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, 2012, 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 letters of credit 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,	2012			2011
	-Millions of Dollars-
Operating Activities	$	113		$	149
Investing Activities		(134	)		(132	)
Financing Activities		45			13

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. UNS Energy, TEP, UNS Gas, and UNS Electric typically use their revolving credit facilities to fund their business activities during periods when sales are seasonally lower.

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 2012, net cash flows from operating activities were $36 million lower than they were in the same period last year due to:

• a $26 million decrease in cash receipts from electric and gas sales (net of fuel and purchased energy costs) due in part to lower long-term wholesale margins at TEP and higher coal-related fuel costs paid at TEP;

• a $4 million increase in interest paid, net of amounts capitalized, due to higher interest expense related to debt issued in late 2011 at TEP; and

• a $3 million increase in taxes other than income taxes paid due to higher property tax payments.

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Investing Activities

Net cash flows used for investing activities increased by $2 million in the first six months of 2012 compared with the same period last year. An $8 million decrease in capital expenditures, the receipt of $5 million related to a note receivable held at Millennium, and the receipt of $3 million in insurance proceeds for replacement assets were offset by a $19 million decrease in proceeds from investments in Springerville lease debt compared with the first six months of 2011.

Capital Expenditures

	Actual  Year-to-Date June 30, 2012		Estimate Full Year  2012
	-Millions of Dollars-
TEP	$	142	$	277
UNS Gas		8		13
UNS Electric		16		40
UNS Energy Consolidated	$	166	$	330

Financing Activities

Net cash flows from financing activities were $32 million higher in the first six months of 2012 compared with the same period last year due primarily to a $75 million increase in borrowings (net of repayments) under the revolving credit facilities at UNS Energy and TEP. This increase was partially offset by an $18 million decrease in proceeds from the issuance of long-term debt (net of repayments) and a $14 million increase in scheduled payments on capital lease obligations.

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, 2012, there was $83 million outstanding at a weighted-average interest rate of 1.99%.

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 interest 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.

As of June 30, 2012, we were in compliance with the terms of the UNS Credit Agreement.

Interest Rate Risk

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

Convertible Senior Notes

In March 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due 2035. Between December 2011 and May 2012, UNS Energy issued a series of separate notices of partial redemption of the Convertible Senior Notes by calling all $150 million outstanding. Holders of the called Convertible Senior Notes had the option of converting their interests to Common Stock or receiving par plus accrued interest for the Convertible Senior Notes. The notes were convertible into shares of Common Stock at a conversion rate applicable at the time of each notice. During the first six months 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 was redeemed at par for cash.

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Contractual Obligations

There are no changes in our contractual obligations or other commercial commitments from those reported in our 2011 Annual Report on Form 10-K, other than the following changes in 2012:

Payment Due in Years Ending December 31,	2012		2013		2014		2015		2016		2017 and after			Total
	-Millions of Dollars-
Long Term Debt(1)	$	—	$	—	$	—	$	—	$	—	$	(7	)	$	(7	)
Purchase Obligations:
Fuel		—		1		3		1		—		—			5
Purchased Power		—		9		8		—		—		—			17
Service Agreement		2		2		2		—		—		—			6
Total Additional Contractual
Cash Obligations	$	2	$	12	$	13	$	1	$	—	$	(7	)	$	21

⁽¹⁾  In 2012, $193 million of unsecured tax-exempt bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.5% and are due in 2030. Proceeds were deposited with a trustee and used, together with $7 million of internal cash, to redeem $200 million of 1998 Apache Bonds issued on behalf of TEP. See Note 4.

Dividends on Common Stock

The following table shows the dividends declared to UNS Energy shareholders for 2012:

Declaration Date	Record Date	Payment Date	Dividend Amount Per Share of Common Stock
February 27, 2012	March 12, 2012	March 22, 2012	$0.43
May 3, 2012	June 8, 2012	June 27, 2012	$0.43

Income Tax Position

As of June 30, 2012, UNS Energy and TEP had the following carry-forward amounts:

	UNS Energy			TEP
	Amount		Expiring Year	Amount		Expiring Year
	-Amounts in Millions of Dollars-
Capital Loss	$	8	2015	$	—	—
Federal Net Operating Loss		207	2031		215	2031-2032
State Net Operating Loss		6	2017		9	2016
State Credits		—	—		2	2016-2017
AMT Credit		43	None		24	None
Investment Tax Credits		5	2032		4	2032

The 2010 Federal Tax Relief Act includes provisions that make qualified property placed into service between September 8, 2010 and January 1, 2012, eligible for 100% bonus depreciation for tax purposes. The same law makes qualified property placed in service during 2012 eligible for 50% bonus depreciation for tax purposes. This is an acceleration of tax benefits UNS Energy otherwise would have received over 20 years. As a result of these provisions, UNS Energy did not pay any federal income taxes for the tax year 2011 and does not expect to pay any federal income taxes for 2012.

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’s utility operations, unless otherwise noted.

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Second Quarter of 2012 Compared with Second Quarter of 2011

TEP reported net income of $22 million in the second quarter of 2012 compared with net income of $25 million in the second quarter of 2011. The following factors impacted TEP’s results in the second quarter of 2012:

• a $4 million decline in long-term wholesale margin revenues resulting from a change in the pricing of energy sold under the SRP wholesale contract effective June 2011;

• a $4 million increase in depreciation and amortization expense as a result of an increase in plant-in-service; and

• a $3 million increase in Base O&M due in part to higher scheduled plant maintenance;

partially offset by

• a $7 million increase in retail margin revenues due to a 4.6% increase in retail kilowatt-hour (kWh) sales.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011

TEP reported net income of $20 million for the first six months of 2012 compared with net income of $30 million for the same period in 2011. The following factors impacted TEP’s results in the first six months of 2012:

• a $9 million decline in long-term wholesale margin revenues resulting from a change in the pricing of energy sold under the SRP wholesale contract effective June 2011; and

• a $7 million increase in depreciation and amortization expense as a result of an increase in plant-in-service;

partially offset by

• a $4 million increase in retail margin revenues due to a 1.7% increase in retail kWh sales.

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Utility Sales and Revenues

Changes in the number of customers, weather, economic conditions, and other consumption 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 2012 and 2011:

					Increase (Decrease)
Three Months Ended June 30,	2012		2011		Amount			Percent(1)
Energy Sales, kWh (in Millions)
Electric Retail Sales:
Residential		1,022		943		79			8.4	%
Commercial		539		518		21			4.0	%
Industrial		544		532		12			2.3	%
Mining		270		272		(2	)		(0.8	)%
Public Authorities		65		67		(2	)		(2.4	)%
Total Electric Retail Sales		2,440		2,332		108			4.6	%
Retail Margin Revenues (in Millions):
Residential	$	67	$	61	$	6			9.1	%
Commercial		44		43		1			4.0	%
Industrial		24		24		—			0.0	%
Mining		8		8		—			1.3	%
Public Authorities		3		3		—			(2.9	)%
Total Retail Margin Revenues (Non-GAAP)(2)		146		139		7			5.3	%
Fuel and Purchased Power Revenues		92		84		8			9.9	%
RES & DSM Revenues		10		9		1			5.5	%
Total Retail Revenues (GAAP)	$	248	$	232	$	16			6.9	%
Average Retail Margin Rate (Cents / kWh):
Residential		6.54		6.50		0.04			0.6	%
Commercial		8.21		8.21		—			—
Industrial		4.40		4.49		(0.09	)		(2.0	)%
Mining		2.97		2.91		0.06			2.1	%
Public Authorities		5.04		5.07		(0.03	)		(0.6	)%
Average Retail Margin Revenue		6.00		5.96		0.04			0.7	%
Average Fuel and Purchased Power Revenue		3.77		3.59		0.18			5.0	%
Average RES & DSM Revenue		0.39		0.39		—			—
Total Average Retail Revenue		10.16		9.94		0.22			2.2	%
					Increase (Decrease)
Weather Data:	2012		2011		Amount			Percent(1)
Cooling Degree Days
Three Months Ended June 30		566		390		176			45.1	%
10-Year Average		452		445		7			1.6	%

⁽¹⁾  Percent change calculated on unrounded 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.

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Residential

Residential kWh sales were 8.4% higher in the second quarter of 2012 than they were during the same period last year, leading to an increase in residential margin revenues of 9.1%, or $6 million. Residential use per customer increased by 7.9% primarily due to a 45.1% increase in Cooling Degree Days compared with the same period last year. The average number of residential customers grew by 0.4% in the second quarter of 2012 compared with the same period last year.

Commercial

Commercial kWh sales increased by 4.0% compared with the second quarter of 2011, leading to an increase in commercial margin revenues of $1 million, or 4.0%. Commercial use per customer increased by 3.4% primarily due to hotter weather than the second quarter of 2011. The average number of commercial customers grew by 0.6% in the second quarter of 2012 compared with the same period last year.

Industrial

Industrial kWh sales increased by 2.3% compared with the second quarter of 2011. Industrial margin revenues increased by less than $1 million when compared with the same period of 2011. The increase in margin revenues was less than the change in kWh sales due to usage patterns by certain industrial customers that reduced their demand charges paid to TEP.

Mining

Mining kWh sales decreased by 0.8% in the second quarter of 2012 compared with the same period last year. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

Wholesale Sales and Transmission Revenues

Three Months Ended June 30,	2012		2011
Long-Term Wholesale Revenues:	-Millions of Dollars-
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)	$	—	$	4
Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues		5		6
Total Long-Term Wholesale Revenues		5		10
Transmission Revenues		4		4
Short-Term Wholesale Revenues		13		18
Electric Wholesale Sales (GAAP)	$	22	$	32

⁽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 were $4 million lower than in the second quarter of 2011. The decrease was due primarily to a change in pricing under the SRP contract that took effect in June 2011. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project, below, for more information.

Short-Term Wholesale Revenues

In the second quarters of 2012 and 2011, TEP’s short-term wholesale revenues were $13 million and $18 million, respectively. All revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.

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Utility Sales and Revenues

					Increase (Decrease)
Six Months Ended June 30,	2012		2011		Amount			Percent(1)
Energy Sales, kWh (in Millions)
Electric Retail Sales:
Residential		1,753		1,692		61			3.6	%
Commercial		934		919		15			1.7	%
Industrial		1,012		1,021		(9	)		(0.9	)%
Mining		543		537		6			1.1	%
Public Authorities		116		117		(1	)		(1.1	)%
Total Electric Retail Sales		4,358		4,286		72			1.7	%
Retail Margin Revenues (in Millions):
Residential	$	113	$	108	$	5			4.3	%
Commercial		75		73		2			1.9	%
Industrial		44		45		(1	)		(2.2	)%
Mining		14		16		(2	)		(7.1	)%
Public Authorities		6		6		—			(1.7	)%
Total Retail Margin Revenues (Non-GAAP)(2)		252		248		4			1.6	%
Fuel and Purchased Power Revenues		141		133		8			5.7	%
RES & DSM Revenues		21		24		(3	)		(11.6	)%
Total Retail Revenues (GAAP)	$	414	$	405	$	9			2.1	%
Average Retail Margin Rate (Cents / kWh):
Residential		6.45		6.40		0.05			0.8	%
Commercial		8.02		8.00		0.02			0.3	%
Industrial		4.30		4.36		(0.06	)		(1.4	)%
Mining		2.67		2.91		(0.24	)		(8.2	)%
Public Authorities		5.02		5.05		(0.03	)		(0.6	)%
Average Retail Margin Revenue		5.78		5.78		—			—
Average Fuel and Purchased Power Revenue		3.24		3.11		0.13			4.2	%
Average RES & DSM Revenue		0.49		0.56		(0.07	)		(12.5	)%
Total Average Retail Revenue		9.51		9.45		0.06			0.4	%

					Increase (Decrease)
Weather Data:	2012		2011		Amount		Percent(1)
Cooling Degree Days
Six Months Ended June 30		566		390		176		45.1	%
10-Year Average		453		446		7		1.6	%

⁽¹⁾  Percent change calculated on unrounded 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.

Residential

Residential kWh sales were 3.6% higher in the first half of 2012 than they were during the same period last year, leading to an increase in residential margin revenues of 4.3%, or $5 million. Residential use per customer increased by 3.2% primarily due to a 45.1% increase in Cooling Degree Days compared with the same period last year.

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Commercial

Commercial kWh sales increased by 1.7% compared with the first half of 2011, leading to an increase in margin revenues of 1.9%, or $2 million. Commercial use per customer increased by 1.0% primarily due to hotter weather compared with last year.

Industrial

Industrial kWh sales decreased by 0.9% compared with the first half of 2011. Industrial margin revenues declined by 2.2%, or $1 million compared with the same period of 2011. The decline in margin revenues was greater than the change in kWh sales due to usage patterns by certain industrial customers that reduced their demand charges paid to TEP.

Mining

High copper prices led to increased mining activity, resulting in a 1.1% increase in sales volumes in the first six months of 2012 compared with the same period last year. Margin revenues from mining customers decreased by 7.1%, or $2 million, over the same period last year. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

Wholesale Sales and Transmission Revenues

Six Months Ended June 30,	2012		2011
Long-Term Wholesale Revenues:	-Millions of Dollars-
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)	$	2	$	11
Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues		10		13
Total Long-Term Wholesale Revenues		12		24
Transmission Revenues		8		8
Short-Term Wholesale Revenues		32		35
Electric Wholesale Sales (GAAP)	$	52	$	67

⁽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.

Margin revenues from long-term wholesale contracts were $9 million lower than in the first six months of 2011. This change was due primarily to a change in pricing under the SRP contract that took effect in June 2011. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project, below, for more information.

Short-Term Wholesale Revenues

In the first six months of 2012 and 2011, TEP’s short-term wholesale revenues were $32 million and $35 million, respectively. All revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.

Other Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	-Millions of Dollars-				-Millions of Dollars-
Revenue related to Springerville Units 3 and 4(1)	$	21	$	25	$	43	$	50
Other Revenue		8		7		14		12
Total Other Revenue	$	29	$	32	$	57	$	62

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

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

Operating Expenses

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for the quarter and six months ended June 30, 2012 and 2011 are detailed below:

	Generation and Purchased Power						Fuel and Purchased Power Expense
Three Months Ended June 30,	2012			2011			2012		2011
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation		2,332			2,508		$	60	$	64
Gas-Fired Generation		405			202			18		14
Renewable Generation		19			10			—		—
Reimbursed Fuel Expense for Springerville Units 3 and 4		—			—			2		2
Total Generation		2,756			2,720			80		80
Total Purchased Power		649			678			21		27
Transmission		—			—			1		1
Increase to Reflect PPFAC Recovery Treatment		—			—			13		3
Total Resources		3,405			3,398		$	115	$	111
Less Line Losses and Company Use		(239	)		(208	)
Total Energy Sold		3,166			3,190

	Generation and Purchased Power						Fuel and Purchased Power Expense
Six Months Ended June 30,	2012			2011			2012		2011
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation		4,670			4,873		$	118	$	121
Gas-Fired Generation		695			377			28		25
Renewable Generation		34			17			—		—
Reimbursed Fuel Expense for Springerville Units 3 and 4		—			—			4		5
Total Generation		5,399			5,267			150		151
Total Purchased Power		1,095			1,149			35		44
Transmission		—			—			2		2
Increase (Decrease) to Reflect PPFAC Recovery Treatment		—			—			5		(7)
Total Resources		6,494			6,416		$	192	$	190
Less Line Losses and Company Use		(435	)		(391	)
Total Energy Sold		6,059			6,025

Generation

Total generating output increased during the second quarter and first six months of 2012 compared with the same period last year due to the higher use of TEP’s gas-fired generation. Coal-fired generation decreased by 7.0% in the second quarter and by 4.2% in the first six months of 2012 due in part to the use of natural gas to fuel Sundt Unit 4 instead of higher priced contracted coal.

Purchased Power

Purchased power volumes decreased in the second quarter of 2012 compared with the same period last year due to increased generating output at TEP’s gas-fired generating stations.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	-cents per kWh-				-cents per kWh -
Coal		2.57		2.55		2.51		2.49
Gas		4.30		6.88		4.05		6.57
Purchased Power		3.22		3.90		3.15		3.80
All Sources		3.22		3.38		3.08		3.26

Market Prices

As a participant in the western U.S. wholesale power markets, TEP is directly and indirectly affected by changes in market conditions. The average market price for around-the-clock energy based on the Dow Jones Palo Verde Market Index in the second quarter of 2012 was 18% below the same period in 2011. The average price for natural gas based on the Permian Index in the second quarter of 2012 was lower by 47% compared with the same period in 2011. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during the remainder of 2012.

Average Market Price for Around-the-Clock Energy	$/MWh
Quarter ended June 30, 2012	$	23
Quarter ended June 30, 2011		27
Six months ended June 30, 2012	$	22
Six months ended June 30, 2011		27
Average Market Price for Natural Gas	$/MMBtu
Quarter ended June 30, 2012	$	2.19
Quarter ended June 30, 2011		4.11
Six months ended June 30, 2012	$	2.29
Six months ended June 30, 2011		4.02

O&M

The table below summarizes the items included in TEP’s Other O&M expense. See Results of Operations, Second Quarter of 2012 Compared with Second Quarter of 2011, above for more information.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	-Millions of Dollars-						-Millions of Dollars-
Base O&M (Non-GAAP)(1)	$	60		$	57		$	120		$	119
O&M Recorded in Other Expense		(1	)		(2	)		(3	)		(3	)
Reimbursed Expenses Related to Springerville Units 3 and 4		13			16			27			32
Expenses Related to Customer Funded Renewable Energy and DSM Programs(2)		7			7			17			19
Total Other O&M (GAAP)	$	79		$	78		$	161		$	167

⁽¹⁾ Base O&M is a non-GAAP financial measure and should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is Other O&M less reimbursed expenses and expenses related to customer- funded renewable energy and DSM programs, provides useful information to investors.

⁽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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FACTORS AFFECTING RESULTS OF OPERATIONS

Base Rate Increase Moratorium

Pursuant to the 2008 TEP Rate Order issued by the Arizona Corporation Commission (ACC), TEP’s Base Rates are frozen through at least December 31, 2012. The 2008 TEP Rate Order also prohibited TEP from submitting an application for new Base Rates before June 30, 2012. See 2012 TEP Rate Case, below, for more information. 

Notwithstanding the rate increase moratorium, Base Rates and adjustor mechanisms may change under emergency conditions beyond TEP’s control if the ACC concludes such changes are required to protect the public interest. The moratorium does not preclude TEP from seeking rate relief in the event of the imposition of a federal carbon tax or related federal carbon regulations.

2012 TEP Rate Case

On July 2, 2012, TEP filed a rate request with the ACC. As set forth in the 2008 Settlement Agreement, the parties to the settlement agreed to use their best efforts to have new rates in place no later than 13 months after TEP’s next rate application is filed with the ACC. In accordance with this provision, TEP’s rate application requests that new rates become effective no later than August 1, 2013. The rate application is based on a test year ended December 31, 2011.

The key provisions of TEP’s rate request include:

• an increase in non-fuel retail base rates of $127.8 million, or 15.3%, over adjusted test year revenues;

• an original cost rate base of $1.5 billion, which includes approximately $40 million of post test year adjustments for utility plant that is expected to be in service by December 31, 2012;

• a fair value rate base of $2.3 billion with a proposed rate of return on fair value rate base of 5.68%; and

• the following cost of capital and pro forma capital structure:

	Component Cost			% of Pro Forma Capital Structure			Weighted Average Cost
Common Equity		10.75	%		46.00	%		4.94	%
Long-Term Debt		5.18	%		54.00	%		2.80	%
Total					100.00	%		7.74	%

Lost Fixed Cost Recovery Mechanism

TEP proposed a lost fixed cost recovery mechanism (LFCR) that would allow TEP to recover non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to: (i) compliance with the ACC’s Energy Efficiency (EE) Standard; and (ii) distributed generation requirements under the ACC’s Renewable Energy Standard and Tariff. The LFCR is not a full decoupling mechanism and is not intended to recover lost fixed costs attributable to weather or economic conditions.

Energy Efficiency Resource Plan

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

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Environmental Compliance Adjustor (ECA)

TEP proposed a new adjustor mechanism designed to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA surcharge would be adjusted annually to recover the capital carrying costs on environmental projects under construction, and a return on investment, depreciation expense, taxes, and associated O&M costs for completed projects.

TEP cannot predict the outcome of this proceeding or whether its rate request will be adopted by the ACC in whole or in part.

Purchased Power and Fuel Adjustment Clause

In February 2012, TEP filed its annual PPFAC update report with the ACC. TEP requested an increase in the total PPFAC rate of $77 million to recover under-collected fuel and purchased power costs of approximately $51 million and an increase in forecasted fuel and purchased power costs of approximately $26 million. In March 2012, the ACC approved a PPFAC rate of 0.77 cents per kWh effective April 2012. The new PPFAC rate is expected to provide recovery of approximately $70 million of fuel and purchased power costs over the period of April 2012 through March 2013. Any shortfall not collected under the approved PPFAC rate is expected to be recovered through the PPFAC rate set for the period beginning April 1, 2013. At June 30, 2012, TEP had under-collected fuel and purchased power costs on a billed-to-customers basis of $54 million.

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.

In 2011, the annual impact to TEP’s pre-tax income resulting from operating Springerville Units 3 and 4 was approximately $24 million. In TEP’s 2012 rate case application, TEP proposed passing onto customers approximately $14 million of these pre-tax benefits, thereby lowering the requested amount of rate relief.

TEP recorded pre-tax income of $6 million in the second quarters of 2012 and 2011 related to the operation of these units. 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,
	2012			2011			2012			2011
	-Millions of Dollars-						-Millions of Dollars-
Other Revenues	$	21		$	25		$	43		$	50
Fuel Expense		(2	)		(2	)		(4	)		(5	)
Operations and Maintenance Expense		(13	)		(16	)		(27	)		(32	)
Taxes Other Than Income Taxes		—			(1	)		(1	)		(1	)
Total Pre-Tax Income	$	6		$	6		$	11		$	12

In July 2012, Springerville Unit 3 experienced an unplanned outage. We are investigating the cause and extent of the outage. TEP’s 2012 pre-tax income could be reduced by approximately $3 million if the unit does not meet certain availability requirements under the terms of TEP’s operating agreement with Tri-State.

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Pension and Postretirement Benefit Expense

The table below summarizes TEP’s pension and other postretirement benefit expenses recorded as part of O&M in 2012 and 2011. See Note 7 for more information.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	-Millions of Dollars-				-Millions of Dollars-
Pension Expense Charged to O&M	$	3	$	2	$	5	$	5
Other Postretirement Benefit Expense Charged to O&M		1		1		2		2
Total	$	4	$	3	$	7	$	7

In 2012, TEP expects to record approximately $15 million of pension and other postretirement benefit expense as part of O&M, compared with $14 million in 2011.

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

Prior to June 2011, under the terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, or $22 million annually, and sold the energy at a price based on TEP’s average fuel cost. From June 2011 to December 2011, SRP was required to purchase 73,000 MWh per month. 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. The price of 50% of the MWh sales from June to September is based on the Dow Jones Palo Verde Market Index. Similarly to 2011, we expect approximately 12% of the total energy sold to NTUA in 2012 will be priced based on the Dow Jones Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA.

Long-Term Wholesale Margin and Sensitivity

TEP’s margin on long-term wholesale sales was $2 million during the first six months of 2012, compared with $11 million in the same period last year.

TEP estimates its margin on long-term wholesale sales in 2012 will be $6 million, compared with $13 million in 2011. The estimated decrease is a result of changes in the terms of the SRP contract described above. As of July 18, 2012, the average forward price of on-peak power on the Dow Jones Palo Verde Market Index for the rest of calendar year 2012 was $30 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 2012 pre-tax income related to the SRP contract by approximately $1 million.

Electric Energy Efficiency Standards

In August 2010, the ACC approved new Electric Energy Efficiency Standards (EE Standards) designed to require TEP, UNS Electric, and other affected electric utilities to implement cost-effective programs to reduce customers’ energy consumption. In 2011, TEP’s programs saved energy equal to approximately 1.4% of its 2010 sales. In 2012, the EE Standards target total kWh savings of 3% of 2011 sales. The Electric EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.

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

In May 2012, TEP filed a modification to its proposed 2011-2012 Energy Efficiency Implementation Plan with the ACC. The proposal includes a request for: (i) a performance incentive ranging from approximately $3 million to $4 million; and (ii) the collection of the performance incentive over a period from October 1, 2012 to December 31, 2012. Hearings before an administrative law judge on this matter were completed in July 2012. TEP cannot predict when the administrative law judge will issue a recommendation or when the ACC will issue a final order in this matter.

Decoupling

In December 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona’s EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring utility Retail Rates to separate the recovery of fixed costs from the level of energy consumed. The policy statement allows affected utilities to file rate decoupling proposals in their next general rate case. TEP filed a general rate case in July 2012. See 2012 TEP Rate Case, above.

Renewable Energy Standard and Tariff

In December 2011, the ACC approved TEP’s RES implementation plan including investments of $28 million in 2012 and $8 million in 2013 for company-owned solar projects. In 2011, TEP’s renewable energy investments totaled $28 million. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $1 million pre-tax in 2012 on solar investments made in 2010 and 2011 and approximately $4 million pre-tax in 2013.

In July 2012, TEP filed its 2013 RES implementation plan. TEP’s plan proposes to collect approximately $41 million from customers during 2013. The plan includes a proposal to invest $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. TEP cannot predict if or when the ACC will approve its plan.

Competition

New technological developments and the implementation of the ACC’s 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. Self-generation by TEP’s customers has not had a significant impact to date. In the wholesale market, TEP competes with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy.

Retail Electric Competition Rules

In 1999, the ACC approved the Retail Electric Competition Rules (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. In 2008, the ACC opened an administrative proceeding to address the Rules but has since taken no action. In March 2012, Constellation NewEnergy filed an application 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. We cannot predict what changes, if any, the ACC will make to the Rules or if the ACC will grant a CC&N to an ESP.

Sales to Mining Customers

In the first six months of 2012, kWh sales to TEP’s mining customers increased 1.1% compared with the same period last year. See Utility Sales and Revenues, Mining, above for more information.

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In December 2011, a mining customer’s long-term contract expired and in January 2012 the customer converted to a time-of-use rate. As a result, we expect full year 2012 margin revenues from mining customers will be approximately $1 million lower than 2011.

The continuation of copper prices above $3 per pound has led to increased 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 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. A certificate of environmental compatibility (CEC) from the state line siting committee was approved in December 2011 for the 138 kV transmission line. In June 2012, the ACC finalized the CEC. If the Rosemont Copper Mine reaches full production, it would become TEP’s largest retail customer. TEP would serve approximately 100 MW of the Rosemont Copper Mine’s total estimated load of approximately 110 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, 2012, 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 2012, the average rates paid ranged from 0.06% to 0.26%. At July 18, 2012, the average rate on the debt was 0.17%.

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.

San Juan Mine Fire

In September 2011, a fire at the underground mine that provides coal to San Juan Generating Station (San Juan) caused mining operations to shut down. TEP owns approximately 20% of San Juan, which is operated by PNM. Mining operations resumed in June 2012.

TEP does not expect the mine fire to have a material effect on TEP’s financial condition, results of operations, or cash flows due to the current inventory of previously mined coal and the current low market price of wholesale power. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers through the PPFAC, subject to ACC approval.

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 a regulatory asset or a regulatory liability, or as a component in the statements of other comprehensive income, rather than in the income statement. See Note 9.

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LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

The tables below show the cash available to TEP after capital expenditures, scheduled debt payments, and payments on capital lease obligations:

Six Months Ended June 30,	2012			2011
	-Millions of Dollars-
Net Cash Flows – Operating Activities (GAAP)	$	67		$	106
Amounts from Statements of Cash Flows:
Less: Capital Expenditures		(142	)		(130	)
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)		(75	)		(24	)
Amounts From Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations		(76	)		(62	)
Plus: Proceeds from Investment in Lease Debt		19			38
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)(1)	$	(132	)	$	(48	)

Six Months Ended June 30,	2012			2011
	-Millions of Dollars-
Net Cash Flows – Operating Activities (GAAP)	$	67		$	106
Net Cash Flows – Investing Activities (GAAP)		(117	)		(91	)
Net Cash Flows – Financing Activities (GAAP)		55			(1	)
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)		(75	)		(24	)
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)(1)		(132	)		(48	)

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

Liquidity Outlook

During 2012, TEP expects to generate sufficient internal cash flows to fund the majority of its capital expenditures and operating activities. 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 fund its business activities.

Operating Activities

In the first six months of 2012, net cash flows from operating activities were $39 million lower than in the first six months of 2011 due primarily to:

• a $29 million decrease in cash receipts from electric sales (net of fuel and purchased power costs) due in part to lower long-term wholesale margins and higher coal-related fuel costs paid compared with the first six months of 2011;

• a $6 million increase in interest paid, net of amounts capitalized due in part to the issuance of fixed rate notes in November 2011; and

• a $4 million increase in taxes other than income taxes paid due in part to higher property taxes paid.

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Investing Activities

Net cash flows used for investing activities increased by $26 million in the first six months of 2012 compared with the same period last year. Proceeds from the return of investment in Springerville lease debt decreased by $19 million in the first six months of 2012 compared with the same period last year.

TEP’s capital expenditures were $142 million in the first six months of 2012, compared with $130 million in the same period last year. TEP’s estimated capital expenditures for 2012 are $277 million.

Financing Activities

In the first six months of 2012, net cash from financing activities was $56 million higher than in the same period in 2011 due to:

• an $89 million increase in borrowings (net of repayments) made under TEP’s Revolving Credit Facility;

partially offset by

• an $18 million decrease in proceeds from the issuance of long-term debt (net of repayments); and

• a $14 million increase in scheduled payments on capital lease obligations.

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, 2012, there were $149 million of outstanding borrowings and $1 million of letters of credit 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, 2012, 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 letter of credit was issued pursuant to the 2010 TEP Reimbursement Agreement. The letter of credit 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, 2012, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

2012 Bond Issuances and Redemptions

In March 2012, $177 million of unsecured tax-exempt pollution control bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in March 2030 and may be redeemed at par on or after March 1, 2022. In April 2012, the proceeds of the bond issuance, as well as $7 million of internal cash, were used to redeem $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 4.

In June 2012, approximately $16 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in June 2030 and may be redeemed at par on or after June 1, 2022. In July 2012, the proceeds of the bond issuance were used to redeem approximately $16 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 4.

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Capital Lease Obligations

As of June 30, 2012, TEP had $365 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease obligations:

Leases	Capital Lease  Obligation Balance As of June 30, 2012		Expiration	Renewal/Purchase Option
	-Millions of Dollars-
Springerville Unit 1(1)	$	197	2015	Fair market value purchase option of $159 million(2)
Springerville Coal Handling Facilities Lease		61	2015	Fixed price purchase option of $120 million(3)
Springerville Common Facilities(4)		107	2017 and 2021	Fixed price purchase option of $106 million(3)
Total Capital Lease Obligations	$	365

⁽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 owner 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.

Except for TEP’s 14% equity ownership in Springerville Unit 1 and its 13% equity ownership in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases. TEP may renew the leases or purchase the leased assets at such time. The renewal and purchase option for Springerville Unit 1 and associated Common Facilities is for fair market value as determined at that time, whereas the purchase price option is fixed for the Springerville Coal Handling Facilities and the remaining Common Facilities. See Part II, Item 1.—Legal Proceedings.

Income Tax Position

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

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Contractual Obligations

There have been no changes in TEP’s contractual obligations or other commercial commitments from those reported in our 2011 Annual Report on Form 10-K, other than the following changes in 2012:

Payment Due in Years Ending December 31,	2012		2013		2014		2015		2016		2017 and after			Total
	-Millions of Dollars-
Long Term Debt(1)	$	—	$	—	$	—	$	—	$	—	$	(7	)	$	(7	)
Purchase Obligations
Purchased Power		—		5		—		—		—		—			5
Service Agreement		2		2		2		—		—		—			6
Total Additional Contractual Cash Obligations	$	2	$	7	$	2	$	—	$	—	$	(7	)	$	4

⁽¹⁾  In 2012, $177 million of unsecured tax-exempt pollution control bonds and $16 million of tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.5% and are due in March and June of 2030. Proceeds were deposited with a trustee and used, together with $7 million of internal cash, to redeem $200 million of 1998 Apache Bonds issued on behalf of TEP. See Note 4.

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, 2012, 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 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 quarter of 2012 and 2011. In the first six months of 2012, UNS Gas reported net income of $5 million compared with net income of $7 million in the same period last year. The decrease in net income is due in part to mild weather during the first six months of 2012 compared with the first six months of 2011. The table below provides summary financial information for UNS Gas:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	-Millions of Dollars-				-Millions of Dollars-
Gas Revenues	$	21	$	26	$	72	$	83
Other Revenues		1		—		3		2
Total Operating Revenues		22		26		75		85
Purchased Gas Expense
Increase to Reflect Purchased Gas Adjustor (PGA) Recovery Treatment		11		15		43		52
O&M		6		6		13		13
Depreciation and Amortization		2		2		5		4
Taxes Other Than Income Taxes		1		1		2		2
Total Other Operating Expenses		20		24		63		71
Operating Income		2		2		12		14
Total Interest Expense		2		2		3		3
Income Tax Expense		—		—		4		4
Net Income	$	—	$	—	$	5	$	7

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The tables below include UNS Gas’ therm sales and margin revenues for the second quarters of 2012 and 2011:

					Increase (Decrease)
Three Months Ended June 30,	2012		2011		Amount			Percent(1)
	-Millions of Therms-
Gas Retail Sales:
Residential		9		10		(1	)		(15.6	)%
Commercial		5		5		—			(6.9	)%
Industrial		—		1		(1	)		(6.9	)%
Public Authorities		1		1		—			(27.7	)%
Total Gas Retail Sales		15		17		(2	)		(13.2	)%
Negotiated Sales Program (NSP)		8		7		1			29.3	%
Total Gas Sales		23		24		(1	)		(1.4	)%
Retail Margin Revenues:	-Millions of Dollars-
Residential	$	7	$	8	$	(1	)		(5.5	)%
Commercial		2		2		—			5.0	%
Industrial		—		—		—			—
Public Authorities		—		—		—			(25.0	)%
Total Retail Margin Revenues (Non-GAAP)(2)		9		10		(1	)		(4.1	)%
Transport and NSP		4		5		(1	)		(13.0	)%
Retail Fuel Revenues		8		11		(3	)		(28.1	)%
Total Gas Revenues (GAAP)	$	21	$	26	$	(5	)		(16.3	)%
Weather Data:
Heating Degree Days
Three Months Ended June 30,		2,239		3,215		(976	)		(30.4	)%
10-Year Average		2,474		2,471		3			0.1	%

⁽¹⁾  Percent change calculated on unrounded 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 2012 decreased by 13.2%, due in part to a 30.4% decrease in Heating Degree Days compared with the second quarter of 2011. As a result of lower retail therm sales, retail margin revenues decreased by 4.1%, or $1 million, compared with the second quarter of 2011.

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 through a credit to the PGA mechanism which reduces the gas commodity price.

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					Increase (Decrease)
Six Months Ended June 30,	2012		2011		Amount			Percent(1)
	-Millions of Therms-
Gas Retail Sales:
Residential		39		43		(4	)		(8.4	)%
Commercial		16		17		(1	)		(6.1	)%
Industrial		1		1		—			(13.0	)%
Public Authorities		4		4		—			(11.6	)%
Total Gas Retail Sales		60		65		(5	)		(8.1	)%
Negotiated Sales Program (NSP)		15		13		2			13.2	%
Total Gas Sales		75		78		(3	)		(4.4	)%
Retail Margin Revenues:	-Millions of Dollars-
Residential	$	21	$	22	$	(1	)		(4.1	)%
Commercial		6		6		—			(1.8	)%
Industrial		—		—		—			—
Public Authorities		1		1		—			(7.7	)%
Total Retail Margin Revenues (Non-GAAP)(2)		28		29		(1	)		(3.8	)%
Transport and NSP		7		9		(2	)		(18.8	)%
Retail Fuel Revenues		37		45		(8	)		(18.1	)%
Total Gas Revenues (GAAP)	$	72	$	83	$	(11	)		(13.2	)%
Weather Data:
Heating Degree Days
Six Months Ended June 30,		13,502		15,224		(1,722	)		(11.3	)%
10-Year Average		12,352		12,412		(60	)		(0.5	)%

⁽¹⁾  Percent change calculated on unrounded 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.

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 a 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 2013, based on estimated lost retail therm sales from May through December 2012.

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The table below summarizes UNS Gas’ initial request and the ACC order:

	Initial Request by UNS Gas	ACC Order
Original Cost Rate Base (as of 12/31/2010)	$184 million	$183 million
Revenue Deficiency	$5.6 million	$2.7 million
Cost of Equity	10.5%	9.75%
Actual Capital Structure	51% equity / 49% debt	51% equity / 49% debt
Weighted Average Cost of Capital	8.7%	8.3%

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

Purchased Gas Adjustor (PGA)

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-customers 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. The credit adjustment is expected to return approximately $10 million of over-collected PGA costs to customers. At June 30, 2012, the PGA bank balance was over-collected by $17 million on a billed-to-customers basis.

Gas Energy Efficiency Standards

In 2010, the ACC approved new Gas EE Standards which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2011, the Gas EE Standards targeted total retail therm savings equal to 0.5% of 2010 sales; UNS Gas estimates its total savings in 2011 were 0.2%. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.

New and existing DSM programs, renewable energy technology that displaces gas, and certain energy efficient building codes are acceptable means to meet the Gas EE Standards as set forth by the ACC. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas’ DSM programs and Retail Rates charged to customers for these programs are subject to ACC approval.

In April 2011, UNS Gas filed its 2011-2012 EE implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In April 2012, UNS Gas filed a request to amend its plan to include its 2013 EE plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the EE 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 9.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas expects operating cash flows to fund all of its construction expenditures during 2012. However, 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. 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.

Cash Flows and Capital Expenditures

Cash Flows

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

Six Months Ended June 30,	2012			2011
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	21		$	20
Investing Activities		(8	)		(5	)
Financing Activities		(10	)		(10	)
Net Increase in Cash		3			5
Beginning Cash		38			30
Ending Cash	$	41		$	35

Capital Expenditures

UNS Gas incurred capital expenditures of $8 million in the first six months of 2012. Total capital expenditures for 2012 are estimated to be $13 million.

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, 2012, UNS Gas had no outstanding borrowings or letters of credit 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, 2012, 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

There have been no significant changes in UNS Gas’ contractual obligations or other commercial commitments from those reported in our 2011 Annual Report on Form 10-K, other than the following obligations established in 2012:

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UNS Gas entered into new forward fuel commitments that settle through June 2015 at fixed prices per MMBtu. UNS Gas’ minimum payment obligations for these purchases are $1 million in 2013, $3 million in 2014 and $1 million in 2015.

Dividends on Common Stock

UNS Gas paid dividends to UNS Energy, through UES, of $10 million in February 2012 and in February 2011. 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 (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of June 30, 2012, UNS Gas was in compliance with the terms of its note purchase agreement.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric purchased BMGS from UED for $63 million on July 1, 2011. In accordance with the accounting rules for a transfer between two UNS Energy subsidiaries under common control, UNS Electric’s first and second quarters of 2012 and 2011 both reflect the results of BMGS. The transaction did not impact UNS Energy’s consolidated financial statements. See Note 3.

UNS Electric reported net income of $4 million in the second quarter of 2012 and 2011. In the first six months of 2012 and 2011, UNS Electric reported net income of $7 million. Like TEP, UNS Electric’s operations are generally 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,
	2012		2011		2012		2011
	-Millions of Dollars-
Retail Electric Revenues	$	44	$	44	$	83	$	87
Wholesale Electric Revenues		7		8		15		15
Other Revenues		—		1		1		1
Total Operating Revenues		51		53		99		103
Purchased Energy Expense		22		28		44		53
Fuel Expense		3		2		4		3
Transmission Expense		3		3		5		6
Increase (Decrease) to Reflect PPFAC Recovery		1		—		3		3
O&M		7		6		16		12
Depreciation and Amortization Expense		5		4		9		9
Taxes Other Than Income Taxes		1		1		2		2
Total Other Operating Expenses		42		44		83		88
Operating Income		9		9		16		15
Total Interest Expense		2		2		4		4
Income Tax Expense		3		3		5		4
Net Income	$	4	$	4	$	7	$	7

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The table below shows UNS Electric’s kWh sales and revenues for the second quarters of 2012 and 2011:

					Increase (Decrease)
Three Months Ended June 30,	2012		2011		Amount			Percent(1)
	- Millions of kWh -
Electric Retail Sales:
Residential		205		173		32			18.0	%
Commercial		167		159		8			5.5	%
Industrial		55		54		1			2.0	%
Mining		28		64		(36	)		(56.9	)%
Public Authorities		—		1		(1	)		1.6	%
Total Electric Retail Sales		455		451		4			1.0	%
Retail Margin Revenues:	-Millions of Dollars-
Residential	$	8	$	7	$	1			21.5	%
Commercial		8		8		—			—
Industrial		2		2		—			—
Mining		2		1		1			6.3	%
Public Authorities		—		—		—			—
Total Retail Margin Revenues (Non-GAAP)(2)		20		18		2			8.8	%
Fuel and Purchased Power Revenues		22		24		(2	)		(10.3	)%
RES & DSM Revenues		2		2		—			80.0	%
Total Retail Revenues (GAAP)	$	44	$	44	$	—			0.7	%
	2012		2011
Weather Data:
Cooling Degree Days
Three Months Ended June 30		3,433		2,645		788			29.8	%
10-Year Average		2,877		2,854		23			0.8	%

⁽¹⁾  Percent change calculated on unrounded 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 2012 increased by 1% compared with the same period last year. Hotter weather in the second quarter led to higher kWh sales to residential and commercial classes compared with the same period last year. Sales volumes to mining customers decreased by 56.9% in the second quarter of 2012 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Retail margin revenues in the second quarter of 2012 were consistent with the second quarter of 2011. See Factors Affecting Results of Operations, Mining Customer, below.

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The table below shows UNS Electric’s kWh sales and revenues for the first half of 2012 and 2011:

					Increase (Decrease)
Six Months Ended June 30,	2012		2011		Amount			Percent(1)
	- Millions of kWh -
Electric Retail Sales:
Residential		375		353		22			6.2	%
Commercial		299		290		9			3.0	%
Industrial		108		106		2			2.4	%
Mining		55		123		(68	)		(55.0	)%
Public Authorities		1		1		—			(4.7	)%
Total Electric Retail Sales		838		873		(35	)		(4.0	)%
	-Millions of Dollars-
Retail Margin Revenues:
Residential	$	15	$	13	$	2			11.5	%
Commercial		14		14		—			(2.1	)%
Industrial		5		5		—			—
Mining		3		3		—			6.3	%
Public Authorities		—		—		—			—
Total Retail Margin Revenues (Non-GAAP)(2)		37		35		2			4.0	%
Fuel and Purchased Power Revenues		40		49		(9	)		(16.6	)%
RES & DSM Revenues		6		3		3			93.1	%
Total Retail Revenues (GAAP)	$	83	$	87	$	(4	)		(4.7	)%
	2012		2011
Weather Data:
Cooling Degree Days
Six Months Ended June 30		3,546		2,747		799			29.1	%
10-Year Average		2,993		2,965		28			0.9	%

⁽¹⁾  Percent change calculated on unrounded 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.

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of the ACC’s Electric EE Standards may reduce energy consumption by UNS Electric’s retail customers. In addition, UNS Electric customers have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on UNS Electric’s service. Self-generation by UNS Electric customers has not had a significant impact to date.

Retail Electric Competition Rules

In 1999, the ACC approved the Retail Electric Competition Rules (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. In 2008, the ACC opened an administrative proceeding to address the Rules but has since taken no action. Unless and until the ACC clarifies the Rules and/or grants a Certificate of Convenience and Necessity (CC&N) to an ESP, it is not possible for UNS Electric’s retail customers to use an alternative ESP. We cannot predict what changes, if any, the ACC will make to the Rules or if the ACC will grant a CC&N to an ESP.

Mining Customer

UNS Electric’s largest customer, a copper mine located near Kingman, Arizona, began generating a portion of its own electricity in 2011. In 2012, UNS Electric expects its mining kWh sales to decrease by approximately 50% compared with 2011. However, due to UNS Electric’s Retail Rate structure, UNS Electric expects the margin revenues from this customer to be near the same level as 2011. In the first six months of 2012 and 2011, UNS Electric’s mining-related margin revenues were $3 million.

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Renewable Energy Standard and Tariff

As part of the 2010 UNS Electric rate order, 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 2012 through 2014 in solar photovoltaic projects. We estimate that each $5 million investment would build approximately 1.25 MW of solar capacity.

In July 2012, UNS Electric filed its 2013 RES implementation plan. UNS Electric’s plan proposes to collect approximately $9 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. UNS Electric cannot predict if or when the ACC will approve its plan.

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.

Electric Energy Efficiency Standards

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

In January 2012, the ACC approved UNS Electric’s 2012 EE implementation plan. UNS Electric’s plan includes an annual performance incentive of less than $1 million. In 2011, UNS Electric’s programs saved energy equal to approximately 0.76% of its 2010 sales. In 2012, the EE Standards target total a cumulative kWh savings of 3% of 2011 sales.

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 9.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric expects operating cash flows to fund a portion of its construction expenditures during 2012. Additional sources of funding future 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.

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Cash Flows and Capital Expenditures

Cash Flows

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

Six Months Ended June 30,	2012			2011
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	26		$	27
Investing Activities		(15	)		(13	)
Financing Activities		—			(5	)
Net Increase in Cash		11			9
Beginning Cash		5			11
Ending Cash	$	16		$	20

Capital Expenditures

UNS Electric had capital expenditures of $16 million in the first six months of 2012 and estimates total capital expenditures in 2012 of $40 million.

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 letters of credit to provide credit enhancement for its energy procurement and hedging activities. As of June 30, 2012, UNS Electric had no outstanding borrowings and $1 million of letters of credit issued under the UNS Gas/UNS Electric Revolver.

Contractual Obligations

There have been no significant changes in UNS Electric’s contractual obligations or other commercial commitments from those reported in our 2011 Annual Report on Form 10-K, other than the following obligations established in 2012:

UNS Electric 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, 2012, UNS Electric’s estimated minimum payment obligations for these purchases are $4 million in 2013 and $8 million in 2014.

Dividends on Common Stock

As of June 30, 2012, UNS Electric has not paid dividends. UNS Electric’s ability to pay 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 (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of June 30, 2012, UNS Electric was in compliance with the terms of its note purchase agreement, and the terms of the UNS Gas/UNS Electric Revolver.

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OTHER NON-REPORTABLE BUSINESS SEGMENTS

RESULTS OF OPERATIONS

The table below summarizes the net income/(loss) for the other non-reportable segments:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	-Millions of Dollars-					-Millions of Dollars-
Millennium	$	—	$	1		$	1	$	1
Other(1)		—		(1	)		—		(3	)
Total Other Net Income (Loss)	$	—	$	—		$	1	$	(2	)

⁽¹⁾ Includes parent company expenses, UED, and reconciling adjustments.

UNS Energy Parent Company

UNS Energy parent company expenses primarily include interest expense (net of tax) related to the UNS Energy Convertible Senior Notes and the UNS Credit Agreement.

FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

At June 30, 2012, Millennium had assets of $21 million including a $10 million note receivable due October 2012 and cash balance of $11 million. In July 2012, Millennium paid a $9 million dividend to UNS Energy.

Note Receivable

In 2009, Millennium sold an equity investment and recorded a $6 million gain on the sale. Millennium received an upfront payment of $5 million in 2009 and a $15 million, three-year, 6% secured promissory note with a maturity date of June 2012. In June 2012, at the request of the borrower, Millennium agreed to change the payment provisions and maturity date of the note. The remaining terms of the note, including provisions securing the payment of the loan amount, remain unchanged. Based on the short-term nature of the note and the fair value of the collateral, management expects the carrying value of the note to be fully realizable. Under the modified payment terms, Millennium received principal payments of $5 million and a $0.25 million amendment fee in June 2012, $2.5 million in July 2012, and is entitled to receive monthly payments of $2.5 million plus accrued interest until the outstanding principal amount is paid in full on October 1, 2012.

CRITICAL ACCOUNTING ESTIMATES

There have been no significant changes in our accounting policies from those disclosed in our 2011 Annual Report on Form 10-K.

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.

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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 postretirement benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; cyber attacks or challenges to our information security; and the performance of TEP's generating plants.

ITEM 3. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2011, 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, Salt River Project.

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 2012 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. – LEGAL PROCEEDINGS

See the legal proceedings described in Item 3. – Legal Proceedings in our 2011 Annual Report on Form 10-K and in Note 6 and in Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 6 and Item 2 are incorporated herein by reference.

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-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.

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 request 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.

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 vigorously pursue its legal remedies to confirm the results of the appraisal procedure.

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 2011 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

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.

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ITEM 5. – OTHER INFORMATION

COMPREHENSIVE INCOME

The Financial Accounting Standards Board issued authoritative guidance that eliminated the option to report other comprehensive income in the statement of changes in equity. Rather, an entity must elect to present items of net income and other comprehensive income in one continuous statement or in two separate but consecutive statements. Effective in the first quarter of 2012, we elected to include separate statements of comprehensive income (loss) with our financial statements.

UNS Energy’s and TEP’s comprehensive income for the previous three years are presented below:

	UNS Energy Years Ended December 31,
	2011			2010			2009
	-Thousands of Dollars-
Comprehensive Income
Net Income	$	109,975		$	112,984		$	105,901
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Cash Flow Hedges, net of $2,376; $4,216; and $(33) income taxes		(3,626	)		(6,431	)		51
Reclassification of Realized Losses on
Cash Flow Hedges to Net Income, net of $(1,412); $(2,140); and $(690) income taxes		2,153			3,264			1,053
Supplemental Executive Retirement Plan
Benefit Adjustments, net of $(804); $523; and $33 income taxes		1,158			(800	)		(51	)
Total Other Comprehensive Income (Loss), Net of Income Taxes		(315	)		(3,967	)		1,053
Total Comprehensive Income	$	109,660		$	109,017		$	106,954

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	TEP Years Ended December 31,
	2011			2010			2009
	-Thousands of Dollars-
Comprehensive Income
Net Income	$	85,334		$	108,260		$	90,688
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Cash Flow Hedges, net of $2,331; $4,216; and $(33) income taxes		(3,555	)		(6,431	)		51
Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(1,390); $(2,140); and $(690) income taxes		2,122			3,264			1,053
Supplemental Executive Retirement Plan Benefit Adjustments, net of $(804); $523; and $33 income taxes		1,158			(800	)		(51	)
Total Other Comprehensive Income (Loss), Net of Income Taxes		(275	)		(3,967	)		1,053
Total Comprehensive Income	$	85,059		$	104,293		$	91,741

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, 2012		Twelve Months Ended June 30, 2012
UNS Energy		1.941		2.385
TEP		1.701		2.279

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

ENVIRONMENTAL MATTERS

Clean Air Act Requirements

TEP generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), and other emissions released into the atmosphere. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its generating facilities. Compliance with these changes may reduce operating efficiency.

TEP has sufficient Emission Allowances to comply with acid rain SO₂ regulations.

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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. The EPA issued the final rule in December 2011, establishing standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units.

Navajo

Based on the EPA’s final standards, mercury and particulate emission control equipment may be required at Navajo by 2015. TEP’s share of the estimated capital cost of this equipment for Navajo is less than $1 million for mercury control and approximately $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.

Springerville Generating Station

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

San Juan

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s final standards.

Sundt Generating Station

TEP does not anticipate that the final EPA standards will have a material impact on capital expenditures at Sundt Generating Station.

Four Corners

Based on the EPA’s final standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated capital cost of this equipment is less than $1 million. The annual operating cost associated with the mercury emission control equipment is expected to be less than $1 million.

Climate Change

In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al. v. EPA that carbon dioxide and other greenhouse gases (GHGs) are air pollutants under the Clean Air Act. In 2009, the EPA issued a final Endangerment Finding stating that GHGs endanger public health and welfare. The EPA issued final GHG regulations for new motor vehicles in 2010 triggering GHG permitting requirements for power plants under the Clean Air Act. As of January 2011, air quality permits for new sources and modifications of existing sources must include an analysis for GHG controls. In the near term, based on our current construction plans, we do not expect the new permitting requirements to impact TEP or UNS Electric.

In March 2012, the EPA released its proposed new source performance standard for GHGs. TEP does not anticipate this standard will have any material impact on its existing facilities.

In 2010, New Mexico adopted regulations limiting GHG emissions from power plants. Several parties filed petitions to repeal those regulations and the New Mexico Environmental Improvement Board held hearings on the repeal petitions in November and December 2011. In the first quarter of 2012, the New Mexico Environmental Improvement Board repealed all of the 2010 GHG regulations.

Based on the competing proposals to regulate GHG emissions by federal, state, and local regulatory and legislative bodies and uncertainty in the regulatory and legislative processes, the scope of such requirements and initiatives and their effect on our operations cannot be determined at this time.

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Regional Haze Rules

The EPA's regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA for approval. Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions. The EPA oversees regional haze planning for these facilities.

Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of the San Juan, Four Corners, and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants.

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the National Renewable Energy Laboratory in partnership with the Department of the Interior and the Department of Energy. The report addresses potential energy, environmental, and economic issues related to compliance with the regional haze rule. The report was submitted to the EPA in January 2012. A final BART rule is expected later in 2012. If the EPA determines that selective catalytic reduction (SCR) is required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital expenditure for the required baghouses would be approximately $43 million. The cost of required pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.

San Juan

In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years in order to reduce NOx and control sulfuric acid emissions. San Juan is able to meet the FIP’s SO₂ limit with current emissions control equipment. TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180 million and $200 million.

In 2011, PNM filed a petition for review of, and a motion to stay the implementation of the FIP with the Tenth Circuit U.S. Court of Appeals (Circuit Court). In addition, PNM 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 the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and EPA. In March 2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. In July 2012, the EPA issued a 90-day stay to allow the State of New Mexico, the EPA, PNM, and other interested parties to evaluate alternatives to the final FIP.

Several environmental groups were granted permission to join in opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted permission to join in opposition to that appeal. In April 2012, PNM, the State of New Mexico, and WildEarth Guardians individually filed briefs on the merits in their respective Circuit Court appeals. TEP cannot predict the ultimate outcome of these matters.

Four Corners

In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that it had originally issued in 2010. If approved, the revised plan would require the installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the capital costs to install SCR is approximately $35 million.

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Sundt Generating Station

The EPA is required to issue a proposal regarding unaddressed state regional haze compliance issues in December 2012. The proposal may, among other things, include a determination regarding whether Sundt Unit 4 could be regulated under certain regional haze provisions.

Springerville

Regional haze regulations requiring emission control upgrades are not applicable to Springerville at this time and are not likely to impact Springerville operations until 2018 or later.

Coal Combustion Residuals

In 2010, the EPA published its proposed regulations governing the handling and disposal of coal ash and other Coal Combustion Residuals (CCRs). The EPA has proposed regulating CCRs as either non-hazardous solid waste or hazardous waste. The hazardous waste alternative would require additional capital investments and operational costs associated with storage and handling at plants and transportation to the disposal locations. Both the hazardous waste and non-hazardous solid waste alternatives would require liners for new ash landfills or expansions to existing ash landfills. The rules will apply to CCRs produced by all of TEP’s coal-fired generating assets. San Juan may also be subject to separate regulations being drafted by the Office of Surface Mining Reclamation and Enforcement because it disposes of CCRs in surface mine pits.

The EPA has not yet indicated a preference for an alternative. Each option would allow CCRs to be beneficially reused or recycled as components of other products. The EPA has indicated that it will issue a final rule by the end of 2012.  The financial impact of this rulemaking to TEP, if any, cannot be determined at this time.

ITEM 6. – EXHIBITS

See Exhibit Index.

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SIGNATURES

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

	UNS ENERGY CORPORATION
	(Registrant)
Date: July 30, 2012	/s/ Kevin P. Larson
	Kevin P. Larson
	Senior Vice President and Principal
	Financial Officer

	TUCSON ELECTRIC POWER COMPANY
	(Registrant)
Date: July 30, 2012		/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Principal
		Financial Officer

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EXHIBIT INDEX

*4(a)	—	Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project) (Form 8-K dated June 21, 2012 – Exhibit 4(a)).
*4(b)	—	Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project) (Form 8-K dated June 21, 2012 – Exhibit 4(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, 2012, 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 incorporate herein by reference.

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

*** XBRL materials for Tucson Electric Power Company are deemed not filed or part of a registration statement or prospectus for the purposes of Section 11 or 12 of the Securities Act of 1933, as amended, and are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

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