Tucson Electric Power 10Q 2011 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2011


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

For the transition period from to .


Commission	Registrant; State of Incorporation;	IRS Employer
File Number	Address; and Telephone Number	Identification Number

1-13739	UNISOURCE ENERGY CORPORATION	86-0786732
	(An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000

1-5924	TUCSON ELECTRIC POWER COMPANY	86-0062700
	(An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000

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.

UniSource Energy Corporation Yesþ Noo

Tucson Electric Power Company (1) Yeso Noþ


(1)		Tucson Electric Power Company is not required to file reports under the Exchange Act. However, Tucson Electric Power Company has filed all Exchange Act reports for the preceding 12 months.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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).

UniSource Energy Corporation Yesþ Noo

Tucson Electric Power Company Yesþ Noo

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):


UniSource Energy Corporation


Large accelerated filerþ	Accelerated filero		Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)


Tucson Electric Power Company


Large accelerated filero	Accelerated filero		Non-accelerated filerþ	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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

UniSource Energy Corporation Yeso Noþ

Tucson Electric Power Company Yeso Noþ

As of October 20, 2011, 36,922,643 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of October 20, 2011, Tucson Electric Power Company had 32,139,434 shares of common stock outstanding, no par value, all of which were held by UniSource Energy Corporation.

This combined Form 10-Q is separately filed by UniSource Energy Corporation and Tucson Electric Power Company. Information contained in this document relating to Tucson Electric Power Company is filed by UniSource 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 UniSource Energy Corporation or its subsidiaries, except as it may relate to Tucson Electric Power Company.

Table of Contents


Definitions	iv

PART I

Reports of Independent Registered Public Accounting Firm		1

Item 1. — Financial Statements		3

UniSource Energy Corporation

Condensed Consolidated Statements of Income		3

Condensed Consolidated Statements of Cash Flows		4

Condensed Consolidated Balance Sheets		5

Condensed Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income		7

Tucson Electric Power Company

Condensed Consolidated Statements of Income		8

Condensed Consolidated Statements of Cash Flows		9

Condensed Consolidated Balance Sheets		10

Condensed Consolidated Statement of Changes in Stockholder’s Equity and Comprehensive Income		12

Notes to Condensed Consolidated Financial Statements — Unaudited		13

Note 1. Nature of Operations and Basis of Accounting Presentation		13

Note 2. Regulatory Matters		18

Note 3. Business Segments		19

Note 4. Debt and Credit Facilities		22

Note 5. Income Taxes		23

Note 6. Commitments, Contingencies and Proposed Environmental Matters		23

Note 7. Employee Benefit Plans		30

Note 8. Share-Based Compensation Plans		30

Note 9. Fair Value Measurements		31

Note 10. UniSource Energy Earnings Per Share		36

Note 11. Stockholders’ Equity		38

Note 12. Recently Issued Accounting Pronouncements		38

Note 13. Supplemental Cash Flow Information		39

Note 14. Accounting for Derivative Instruments, Trading Activities and Hedging Activities		40

Note 15. Review by Independent Registered Public Accounting Firm		43

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations		44

UniSource Energy Consolidated		44

Overview of Consolidated Business		44

Outlook and Strategies		45

Results of Operations		45

Liquidity and Capital Resources		47

Tucson Electric Power Company		51

Results of Operations		51

Factors Affecting Results of Operations		59

Liquidity and Capital Resources		63

UNS Gas		66

Results of Operations		66

Factors Affecting Results of Operations		68

Liquidity and Capital Resources		69

UNS Electric		71

Results of Operations		71

Factors Affecting Results of Operations		73

Liquidity and Capital Resources		74

Other Non-Reportable Business Segments		76

Results of Operations		76

Factors Affecting Results of Operations		77

Critical Accounting Estimates		77



Recently Issued Accounting Pronouncements			77

Safe Harbor for Forward-Looking Statements			78

Item 3. — Quantitative and Qualitative Disclosures about Market Risk			78

Item 4. — Controls and Procedures			81

PART II — OTHER INFORMATION

Item 1. — Legal Proceedings			81

Item 1A. — Risk Factors			81

Item 2. — Unregistered Sale of Equity Securities and Use of Proceeds			81

Item 5. — Other Information			82

Ratio of Earnings to Fixed Charges			82

Environmental Matters			82

Item 6. Exhibits			85

Signatures			86

Exhibit Index			87

Exhibit 12(a)
Exhibit 12(b)
Exhibit 15
Exhibit 31(a)
Exhibit 31(b)
Exhibit 31(c)
Exhibit 31(d)
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

iii

DEFINITIONS

The abbreviations and acronyms used in the 2011 third quarter report on Form 10-Q are defined below:


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 group of financial institutions

ACC		Arizona Corporation Commission

AFUDC		Allowance for Funds Used During Construction

AMT		Alternative Minimum Tax

AOCI		Accumulated Other Comprehensive Income

APS		Arizona Public Service Company

Augusta		Augusta Resources Corporation

BART		Best Available Retrofit Technology

BMGS		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		Coal combustion residuals

CO₂		Carbon dioxide

Common Stock		UniSource Energy’s common stock, without par value

Company		UniSource Energy Corporation

Cooling Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures

DSM		Demand side management

EE Standards		Electric Energy Efficiency Standards

El Paso		El Paso Electric Company

Emission Allowance(s)		An allowance issued by the Environmental Protection Agency which permits emission of one ton of sulfur dioxide or one ton of nitrogen oxide. These allowances can be bought and sold

Energy		The amount of power produced over a given period of time measured in MWh

EPA		Environmental Protection Agency

FERC		Federal Energy Regulatory Commission

Four Corners		Four Corners Generating Station

GAAP		Generally Accepted Accounting Principles

Gas EE Standards		Gas Energy Efficiency Standards

GBtu		Billion British thermal units

Heating Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65

IDBs		Industrial Development Bonds

IRS		Internal Revenue Service

kWh		Kilowatt-hour(s)

LIBOR		London Interbank Offered Rate

Luna		Luna Generating Station

Millennium		Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy

MMBtu		Million British thermal units

Mortgage Bonds		Mortgage Bonds issued under the 1992 Mortgage

MW		Megawatt(s)

MWh		Megawatt-hour(s)

Navajo		Navajo Generating Station

O&M		Operations and Maintenance Expense

NTUA		Navajo Tribal Utility Authority

NOL		Net Operating Loss

PGA		Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers

PNM		Public Service Company of New Mexico

PPA		Power purchase agreement


PPFAC		Purchased Power and Fuel Adjustment Clause

RES		Renewable Energy Standard

San Juan		San Juan Generating Station

SCR		Selective Catalytic Reduction

SES		Southwest Energy Solutions

Springerville		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

Staff Accounting Bulletin 108		Staff Accounting Bulletin No. 108 (ASC 250-10), Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements

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 UniSource Energy

TEP Credit Agreement		Second Amended and Restated Credit Agreement between TEP and a syndicate of banks, dated as of November 9, 2010

TEP Letter of Credit Facility		Letter of credit facility under the TEP Credit Agreement

TEP Revolving Credit Facility		Revolving credit facility under the TEP Credit Agreement

Therm		A unit of heating value equivalent to 100,000 Btus

Tri-State		Tri-State Generation and Transmission Association

UED		UniSource Energy Development Company, a wholly-owned subsidiary of UniSource Energy, which engages in developing generation resources and other project development services and related activities

UED Credit Agreement		Credit agreement between UED and a syndicate of banks, dated as of March 26, 2009, as amended, and guaranteed by UniSource Energy. Repaid on July 1, 2011

UES		UniSource Energy Services, Inc., an intermediate holding company established to own the operating companies UNS Gas and UNS Electric

UniSource Credit Agreement		Second Amended and Restated Credit Agreement between UniSource Energy and a syndicate of banks, dated as of November 9, 2010

UniSource Energy		UniSource Energy Corporation

UNS Electric		UNS Electric, Inc., a wholly-owned subsidiary of UES

UNS Electric Credit Agreement		Credit Agreement among UNS Electric, as borrower, and Union Bank, N.A., dated as of August 10, 2011

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

USFS		United States Forest Service

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of
UniSource Energy Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of UniSource Energy Corporation and its subsidiaries (the “Company”) as of September 30, 2011, and the related condensed consolidated statements of income for the three and nine-month periods ended September 30, 2011 and 2010, the condensed consolidated statement of changes in stockholders’ equity and comprehensive income for the nine-month period ended September 30, 2011 and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2011 and 2010. 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, 2010, 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 March 1, 2011, 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, 2010, 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
October 31, 2011

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 September 30, 2011, and the related condensed consolidated statements of income for the three and nine-month periods ended September 30, 2011 and 2010, the condensed consolidated statement of changes in stockholder’s equity and comprehensive income for the nine-month period ended September 30, 2011, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2011 and 2010. These interim financial statements are the responsibility of the Company’s management.

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, 2010, 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 present herein), and in our report dated March 1, 2011, 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, 2010, 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
October 31, 2011

PART I — FINANCIAL INFORMATION


ITEM 1.		FINANCIAL STATEMENTS

UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME


Three Months Ended							Nine Months Ended
September 30,							September 30,
2011			2010				2011			2010
(Unaudited)							(Unaudited)
-Thousands of Dollars-							-Thousands of Dollars-
(Except Per Share Amounts)							(Except Per Share Amounts)
						Operating Revenues
$	363,385		$	360,028		Electric Retail Sales	$	856,216		$	824,714
	41,847			36,838		Electric Wholesale Sales		121,506			102,397
	—			—		California Power Exchange (CPX) Provision for Wholesale Refunds		—			(2,970	)
	16,831			16,140		Gas Revenue		99,041			96,598
	28,884			25,824		Other Revenues		88,624			76,053

	450,947			438,830		Total Operating Revenues		1,165,387			1,096,792


						Operating Expenses
	98,962			89,874		Fuel		252,103			219,192
	88,734			93,889		Purchased Energy		233,344			243,285
	(1,354	)		3,380		Transmission		4,612			8,688
	(3,576	)		(11,735	)	Decrease to Reflect PPFAC/PGA Recovery Treatment		(5,174	)		(34,260	)

	182,766			175,408		Total Fuel and Purchased Energy		484,885			436,905
	90,781			88,936		Other Operations and Maintenance		281,888			258,979
	33,553			32,450		Depreciation		99,653			95,773
	7,882			7,177		Amortization		22,513			20,797
	12,205			11,334		Taxes Other Than Income Taxes		36,579			35,559

	327,187			315,305		Total Operating Expenses		925,518			848,013

	123,760			123,525		Operating Income		239,869			248,779


						Other Income (Deductions)
	1,919			2,011		Interest Income		3,739			5,891
	1,678			2,196		Other Income		7,155			9,334
	(1,412	)		(2,456	)	Other Expense		(2,830	)		(9,359	)

	2,185			1,751		Total Other Income (Deductions)		8,064			5,866


						Interest Expense
	17,945			15,928		Long-Term Debt		54,240			46,984
	10,248			11,616		Capital Leases		30,108			35,124
	(88	)		(1,726	)	Other Interest Expense, Net of Interest Capitalized		(1,118	)		(1,213	)

	28,105			25,818		Total Interest Expense		83,230			80,895


	97,840			99,458		Income Before Income Taxes		164,703			173,750
	38,128			43,793		Income Tax Expense		62,916			72,018


$	59,712		$	55,665		Net Income	$	101,787		$	101,732


						Weighted-Average Shares of Common Stock Outstanding (000)
	37,053			36,533		Basic		36,930			36,321


	41,777			41,141		Diluted		41,577			40,923


						Earnings per Share
$	1.61		$	1.52		Basic	$	2.76		$	2.80


$	1.46		$	1.38		Diluted	$	2.53		$	2.57


$	0.42		$	0.39		Dividends Declared per Share	$	1.26		$	1.17

See Notes to Condensed Consolidated Financial Statements.

UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	September 30,
	2011			2010
	(Unaudited)
	-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	876,960		$	848,308
Cash Receipts from Electric Wholesale Sales		137,029			138,236
Cash Receipts from Gas Sales		125,913			124,922
Cash Receipts from Operating Springerville Units 3 & 4		80,558			67,593
Cash Receipts from Gas Wholesale Sales		12,404			—
Performance Deposits Received		6,340			16,200
Interest Received		5,400			9,029
Income Tax Refunds Received		3,819			—
Other Cash Receipts		16,830			21,557
Purchased Energy Costs Paid		(246,452	)		(286,314	)
Payment of Other Operations and Maintenance Costs		(220,625	)		(178,123	)
Fuel Costs Paid		(212,791	)		(182,703	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(123,166	)		(106,701	)
Wages Paid, Net of Amounts Capitalized		(92,924	)		(94,490	)
Interest Paid, Net of Amounts Capitalized		(56,060	)		(49,751	)
Capital Lease Interest Paid		(31,558	)		(37,106	)
Wholesale Gas Costs Paid		(11,822	)		—
Performance Deposit Paid		(3,840	)		(17,200	)
Income Taxes Paid		(700	)		(11,246	)
Other Cash Payments		(4,828	)		(6,678	)

Net Cash Flows — Operating Activities		260,487			255,533


Cash Flows from Investing Activities
Capital Expenditures		(263,153	)		(208,042	)
Purchase of Sundt Unit 4 Lease Asset		—			(51,389	)
Purchase of Intangibles — Renewable Energy Credits		(4,102	)		(6,241	)
Prepayment Deposit on UED Debt		—			(3,188	)
Other Cash Payments		(578	)		(820	)
Return of Investment in Springerville Lease Debt		38,353			25,615
Proceeds from Sale of Land and Buildings		2,512			—
Other Cash Receipts		11,050			10,933

Net Cash Flows — Investing Activities		(215,918	)		(233,132	)


Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities		238,000			231,000
Proceeds from Issuance of Long-Term Debt		91,080			39,570
Proceeds from Stock Options Exercised		7,487			8,896
Other Cash Receipts		3,057			8,777
Repayments of Borrowings Under Revolving Credit Facilities		(189,000	)		(199,000	)
Payments of Capital Lease Obligations		(74,381	)		(55,970	)
Repayment of Long-Term Debt		(79,665	)		(19,445	)
Common Stock Dividends Paid		(46,382	)		(42,326	)
Payment of Debt Issue/Retirement Costs		(759	)		(2,099	)
Other Cash Payments		(1,168	)		(1,827	)

Net Cash Flows — Financing Activities		(51,731	)		(32,424	)


Net Increase (Decrease) in Cash and Cash Equivalents		(7,162	)		(10,023	)
Cash and Cash Equivalents, Beginning of Year		67,599			76,922

Cash and Cash Equivalents, End of Period	$	60,437		$	66,899

See Note 13 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2011			2010
	(Unaudited)
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,634,661		$	4,452,928
Utility Plant Under Capital Leases		582,669			583,374
Construction Work in Progress		222,235			210,971

Total Utility Plant		5,439,565			5,247,273
Less Accumulated Depreciation and Amortization		(1,859,610	)		(1,824,843	)
Less Accumulated Amortization of Capital Lease Assets		(472,683	)		(460,932	)

Total Utility Plant — Net		3,107,272			2,961,498


Investments and Other Property
Investments in Lease Debt and Equity		66,103			103,844
Other		34,413			61,676

Total Investments and Other Property		100,516			165,520


Current Assets
Cash and Cash Equivalents		60,437			67,599
Accounts Receivable — Customer		122,916			98,333
Unbilled Accounts Receivable		49,087			53,084
Allowance for Doubtful Accounts		(5,521	)		(6,125	)
Fuel Inventory		25,170			29,216
Materials and Supplies		70,073			65,832
Derivative Instruments		9,811			5,214
Regulatory Assets — Current		76,146			56,962
Deferred Income Taxes — Current		17,884			30,822
Other		39,431			30,091

Total Current Assets		465,434			431,028


Regulatory and Other Assets
Regulatory Assets — Noncurrent		158,439			192,966
Derivative Instruments		3,946			9,806
Other Assets		27,762			30,425

Total Regulatory and Other Assets		190,147			233,197


Total Assets	$	3,863,369		$	3,791,243

See Notes to Condensed Consolidated Financial Statements.

(Continued)

UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,		December 31,
	2011		2010
	(Unaudited)
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	893,669	$	830,756
Capital Lease Obligations		350,912		429,074
Long-Term Debt		1,454,615		1,352,977

Total Capitalization		2,699,196		2,612,807


Current Liabilities
Current Obligations Under Capital Leases		77,060		60,347
Borrowings Under Revolving Credit Facility		5,000		—
Current Maturities of Long-Term Debt		—		57,000
Accounts Payable — Trade		104,695		108,950
Interest Accrued		23,126		39,120
Accrued Taxes Other than Income Taxes		56,188		39,140
Accrued Employee Expenses		26,520		26,969
Customer Deposits		31,450		29,795
Regulatory Liabilities — Current		44,725		69,483
Derivative Instruments		27,695		30,574
Other		5,248		1,678

Total Current Liabilities		401,707		463,056


Deferred Credits and Other Liabilities
Deferred Income Taxes — Noncurrent		297,767		246,466
Regulatory Liabilities — Noncurrent		228,825		201,329
Derivative Instruments		19,668		22,969
Pension and Other Postretirement Benefits		113,330		127,343
Other		102,876		117,273

Total Deferred Credits and Other Liabilities		762,466		715,380


Commitments, Contingencies and Proposed Environmental Matters (Note 6)


Total Capitalization and Other Liabilities	$	3,863,369	$	3,791,243

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


								Accumulated
	Common							Other			Total
	Shares		Common		Accumulated			Comprehensive			Stockholders’
	Outstanding*		Stock		Earnings			Loss			Equity
	(Unaudited)
	-Thousands of Dollars-

Balances at December 31, 2010		36,542	$	715,688	$	124,837		$	(9,769	)	$	830,756


Comprehensive Income:
2011 Year-to-Date Net Income						101,787						101,787

Unrealized Loss on Cash Flow Hedges (net of $2,109 income taxes)									(3,222	)		(3,222	)

Reclassification of Realized Losses on Cash Flow Hedges to Net Income (net of $1,153 income taxes)									1,761			1,761

Employee Benefit Obligations Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $141 income taxes)									223			223


Total Comprehensive Income												100,549

Dividends, Including Non-Cash Dividend Equivalents						(46,664	)					(46,664	)
Shares Issued for Stock Options		281		7,487								7,487
Shares Issued under Stock Compensation Plans		57
Other				1,541								1,541


Balances at September 30, 2011		36,880	$	724,716	$	179,960		$	(11,007	)	$	893,669


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

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME


Three Months Ended							Nine Months Ended
September 30,							September 30,
2011			2010				2011			2010
(Unaudited)							(Unaudited)
- Thousands of Dollars -							-Thousands of Dollars-
						Operating Revenues
$	308,924		$	300,348		Electric Retail Sales	$	714,278		$	685,322
	29,608			26,731		Electric Wholesale Sales		96,623			96,997
	—			—		California Power Exchange (CPX) Provision for Wholesale Refunds		—			(2,970	)
	31,313			27,559		Other Revenues		93,765			81,066

	369,845			354,638		Total Operating Revenues		904,666			860,415


						Operating Expenses
	95,977			85,174		Fuel		246,563			209,843
	40,509			47,909		Purchased Power		84,189			105,900
	(4,266	)		972		Transmission		(2,339	)		2,818
	1,115			(12,724	)	Increase (Decrease) to Reflect PPFAC Recovery Treatment		(5,146	)		(23,023	)

	133,335			121,331		Total Fuel and Purchased Energy		323,267			295,538
	79,837			74,687		Other Operations and Maintenance		246,423			219,664
	26,541			25,190		Depreciation		78,124			74,143
	8,798			8,153		Amortization		25,282			23,963
	9,855			9,222		Taxes Other Than Income Taxes		29,803			28,903

	258,366			238,583		Total Operating Expenses		702,899			642,211

	111,479			116,055		Operating Income		201,767			218,204


						Other Income (Deductions)
	1,666			1,725		Interest Income		2,983			5,111
	229			2,018		Other Income		4,597			4,351
	(2,754	)		(2,468	)	Other Expense		(7,751	)		(7,352	)

	(859	)		1,275		Total Other Income (Deductions)		(171	)		2,110


						Interest Expense
	12,081			10,223		Long-Term Debt		36,493			30,255
	10,248			11,614		Capital Leases		30,107			35,118
	(44	)		(1,683	)	Other Interest Expense, Net of Interest Capitalized		(881	)		(1,641	)

	22,285			20,154		Total Interest Expense		65,719			63,732


	88,335			97,176		Income Before Income Taxes		135,877			156,582
	34,423			37,472		Income Tax Expense		52,104			58,447


$	53,912		$	59,704		Net Income	$	83,773		$	98,135

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	September 30,
	2011			2010
	(Unaudited)
	-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	723,107		$	704,027
Cash Receipts from Electric Wholesale Sales		114,061			140,207
Cash Receipts from Operating Springerville Units 3 & 4		80,558			67,593
Cash Receipts from Gas Wholesale Sales		11,825			—
Reimbursement of Affiliate Charges		13,928			13,781
Interest Received		5,361			8,986
Income Tax Refunds Received		4,360			3,369
Performance Deposits Received		1,640			5,040
Other Cash Receipts		12,466			13,738
Payment of Other Operations and Maintenance Costs		(215,896	)		(171,624	)
Fuel Costs Paid		(208,675	)		(173,796	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(93,444	)		(88,390	)
Purchased Power Costs Paid		(82,321	)		(137,051	)
Wages Paid, Net of Amounts Capitalized		(76,739	)		(76,637	)
Interest Paid, Net of Amounts Capitalized		(34,161	)		(28,841	)
Capital Lease Interest Paid		(31,558	)		(37,099	)
Wholesale Gas Cost Paid		(11,822	)		—
Income Taxes Paid		(2,346	)		(14,865	)
Perfomance Deposit Paid		(1,640	)		(5,040	)
Other Cash Payments		(3,160	)		(2,487	)

Net Cash Flows — Operating Activities		205,544			220,911


Cash Flows from Investing Activities
Capital Expenditures		(193,714	)		(171,813	)
Purchase of Sundt Unit 4 Lease Asset		—			(51,389	)
Purchase of Intangibles — Renewable Energy Credits		(4,000	)		(7,073	)
Other Cash Payments		(558	)		(1	)
Return of Investment in Springerville Lease Debt		38,353			25,615
Other Cash Receipts		6,648			6,863

Net Cash Flows — Investing Activities		(153,271	)		(197,798	)


Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility		120,000			177,000
Proceeds from Issuance of Long-Term Debt		11,080			30,000
Equity Investment from UniSource Energy		—			15,000
Other Cash Receipts		1,051			1,831
Repayments of Borrowings Under Revolving Credit Facility		(115,000	)		(157,000	)
Payments of Capital Lease Obligations		(74,343	)		(55,889	)
Dividends Paid to UniSource Energy		—			(30,000	)
Other Cash Payments		(1,019	)		(2,682	)

Net Cash Flows — Financing Activities		(58,231	)		(21,740	)


Net Increase (Decrease) in Cash and Cash Equivalents		(5,958	)		1,373
Cash and Cash Equivalents, Beginning of Year		19,983			22,418

Cash and Cash Equivalents, End of Period	$	14,025		$	23,791

See Note 13 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2011			2010
	(Unaudited)
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,014,702		$	3,863,431
Utility Plant Under Capital Leases		582,669			582,669
Construction Work in Progress		140,036			153,981

Total Utility Plant		4,737,407			4,600,081
Less Accumulated Depreciation and Amortization		(1,748,845	)		(1,729,747	)
Less Accumulated Amortization of Capital Lease Assets		(472,683	)		(460,257	)

Total Utility Plant — Net		2,515,879			2,410,077


Investments and Other Property
Investments in Lease Debt and Equity		66,103			103,844
Other		32,598			43,588

Total Investments and Other Property		98,701			147,432


Current Assets
Cash and Cash Equivalents		14,025			19,983
Accounts Receivable — Customer		104,812			78,200
Unbilled Accounts Receivable		39,817			32,217
Allowance for Doubtful Accounts		(3,779	)		(4,106	)
Accounts Receivable — Due from Affiliates		3,289			5,444
Fuel Inventory		24,887			29,209
Materials and Supplies		58,910			54,732
Derivative Instruments		2,104			1,318
Regulatory Assets — Current		56,642			34,023
Deferred Income Taxes — Current		21,324			32,077
Other		22,352			26,467

Total Current Assets		344,383			309,564


Regulatory and Other Assets
Regulatory Assets — Noncurrent		147,169			182,304
Derivative Instruments		1,360			1,834
Other Assets		22,354			24,767

Total Regulatory and Other Assets		170,883			208,905


Total Assets	$	3,129,846		$	3,075,978

See Notes to Condensed Consolidated Financial Statements.

(Continued)

TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,		December 31,
	2011		2010
	(Unaudited)
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	792,451	$	709,884
Capital Lease Obligations		350,912		429,074
Long-Term Debt		1,003,615		1,003,615

Total Capitalization		2,146,978		2,142,573


Current Liabilities
Current Obligations Under Capital Leases		77,060		60,309
Borrowings Under Revolving Credit Facility		5,000		—
Accounts Payable — Trade		79,693		77,021
Accounts Payable — Due to Affiliates		7,669		3,990
Interest Accrued		20,525		31,771
Accrued Taxes Other than Income Taxes		46,414		29,873
Accrued Employee Expenses		23,713		23,710
Customer Deposits		22,716		21,191
Derivative Instruments		5,432		7,288
Regulatory Liabilities — Current		30,534		58,936
Other		3,735		3,379

Total Current Liabilities		322,491		317,468


Deferred Credits and Other Liabilities
Deferred Income Taxes — Noncurrent		269,968		227,615
Regulatory Liabilities — Noncurrent		195,052		170,223
Derivative Instruments		13,049		11,650
Pension and Other Postretirement Benefits		107,957		120,590
Other		74,351		85,859

Total Deferred Credits and Other Liabilities		660,377		615,937


Commitments, Contingencies and Proposed Environmental Matters (Note 6)


Total Capitalization and Other Liabilities	$	3,129,846	$	3,075,978

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME


									Accumulated
			Capital						Other			Total
	Common		Stock			Accumulated			Comprehensive			Stockholder’s
	Stock		Expense			Deficit			Loss			Equity
	(Unaudited)
	- Thousands of Dollars -

Balances at December 31, 2010	$	858,971	$	(6,357	)	$	(132,961	)	$	(9,769	)	$	709,884


Comprehensive Income:
2011 Year-to-Date Net Income							83,773						83,773

Unrealized Loss on Cash Flow Hedges (net of $2,088 income taxes)										(3,190	)		(3,190	)

Reclassification of Realized Losses on Cash Flow Hedges to Net Income (net of $1,153 income taxes)										1,761			1,761

Employee Benefit Obligations Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $141 income taxes)										223			223


Total Comprehensive Income													82,567


Balances at September 30, 2011	$	858,971	$	(6,357	)	$	(49,188	)	$	(10,975	)	$	792,451

See Notes to Condensed Consolidated Financial Statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — Unaudited

NOTE 1. NATURE OF OPERATIONS AND BASIS OF ACCOUNTING PRESENTATION

UniSource Energy Corporation (UniSource Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UniSource Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UniSource 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 UniSource Energy’s largest operating subsidiary, representing approximately 81% of UniSource Energy’s total assets as of September 30, 2011. TEP generates, transmits and distributes electricity to approximately 404,000 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 Agriculture Improvement and Power District (SRP).

UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a gas distribution company with approximately 146,000 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 an electric transmission and distribution company with approximately 91,000 retail customers in Mohave and Santa Cruz counties.

In 2008, UED developed the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility includes two natural gas-fired combustion turbines. Prior to July 2011, UNS Electric received energy from BMGS through a power sales agreement with UED. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no impact on UniSource Energy’s consolidated financial statements.

Millennium’s investments in unregulated businesses represent less than 1% of UniSource Energy’s assets as of September 30, 2011. Millennium’s $13 million net loss for 2010, which reflected impairment losses, caused it to be a reportable segment at December 31, 2010. Millennium is not a reportable segment at September 30, 2011.

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

The accompanying quarterly financial statements of UniSource 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. UniSource Energy and TEP reclassified certain amounts in the financial statements to conform to the current year presentation. The year-end condensed balance sheet data was derived from audited financial statements, but it does not include disclosures required by GAAP for audited annual financial statements. This quarterly report should be reviewed in conjunction with UniSource Energy’s and TEP’s 2010 Annual Report on Form 10-K.

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

REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS

In the second quarter of 2011, we identified errors related to amounts recorded, at their dollar value, owed to or payable by TEP for electricity deliveries settled in-kind or to be settled in-kind during prior years under three of our transmission agreements. Transmission, interconnection and certain joint operating agreements typically provide that the parties to such agreements will monitor transmission and delivery losses and other energy imbalances and make payments to each other to compensate for any losses and imbalances. Payments for such losses and imbalances are made in-kind with energy (MWh) rather than cash. The amount of these losses and imbalances is typically a very low portion of the energy flows subject to these agreements and is usually settled on a one day or one month lag. Separately, we also had identified errors in prior years in the calculation of income tax expense arising from not treating Allowance for Equity Funds Used During Construction (AFUDC) as a permanent book to tax difference. We assessed the materiality of these errors on prior period financial statements and concluded they were not material to any prior annual or interim periods, but the cumulative impact, if recognized in 2011, could be material to the annual period ending December 31, 2011 and the interim period ended June 30, 2011. As a result, in accordance with Staff Accounting Bulletin 108 and as set forth in Note 1 to the Financial Statements in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, we revised our prior period financial statements to correct these errors.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

In the third quarter of 2011, we conducted a review of all of our remaining agreements that provided for in-kind payments for transmission and delivery losses or energy imbalances and identified additional errors related to recording, at their dollar value, amounts owed to or payable by TEP for electricity deliveries settled in-kind or to be settled in-kind during prior years. We also identified minor errors to prior year amounts billed to third parties for operations and maintenance expense. We assessed the materiality of these errors, considered together with the errors identified in the first half of 2011, on prior period financial statements and concluded that, while they were not material to any prior annual or interim periods, we should update the prior revision to reflect all of the errors identified in 2011.

The income tax adjustment affected fiscal years 2003 through 2010 for UniSource Energy and fiscal years 2009 and 2010 for TEP. The adjustment for transmission and delivery losses and energy imbalances settled in-kind or to be settled in-kind affected fiscal years 2004 through 2010. The operations and maintenance expense adjustment affected fiscal years 2006 through 2010. The updated revision increased UniSource Energy’s net income by $2 million for both the 2010 and 2009 annual periods and by $3 million in 2008. The updated revision increased TEP’s net income by $1 million for both the 2010 and 2009 annual periods and by $3 million in 2008. UniSource Energy’s Accumulated Earnings increased by $4 million for the periods prior to January 1, 2008, as a result of the revisions.

The revised amounts include reclassifications to conform to the current year presentation. TEP reclassified Other Operations and Maintenance costs of $7 million in 2010, and $6 million in 2009 to Other Expense to correctly account for the regulatory treatment of certain expenses. Additionally, for the nine months ended September 30, 2009, Unisource Energy and TEP reclassified Electric Wholesale Sales of $2 million to Purchased Energy to correctly account for the net settlement of certain wholesale sales contracts.

The revision and reclassifications impacted statements of income and balance sheets as shown in the tables below:


	UniSource Energy
	2011
	Three Months Ended						Three Months Ended				Six Months Ended
	March 31,						June 30,				June 30,
	As			As			As		As		As			As
	Reported			Revised			Reported		Revised		Reported			Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	40,781		$	40,914		$	38,744	$	38,744	$	79,658		$	79,658
Fuel		72,137			71,192			82,563		81,949		154,692			153,141
Purchased Energy		77,640			78,274			66,336		66,336		144,610			144,610
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		(5,793	)		(5,388	)		3,227		3,790		(3,008	)		(1,598	)
Income Tax Expense		3,909			7,468			17,229		17,320		24,731			24,788
Net Income		16,992			13,472			28,574		28,604		41,990			42,076
Basic Earnings Per Share (EPS)		0.46			0.37			0.77		0.77		1.14			1.14
Diluted EPS		0.44			0.36			0.71		0.71		1.07			1.07

Balance Sheet
Deferred Income Taxes — Current		35,210			30,989			34,839		33,219		34,839			33,219
Accounts Receivable — Customer		73,350			88,050			94,618		103,102		94,618			103,102
Regulatory Assets — Noncurrent		191,238			186,812			166,311		161,131		166,311			161,131
Common Stock Equity		824,127			830,577			847,095		849,569		847,095			849,569
Accounts Payable — Trade		97,260			96,862			123,508		122,717		123,508			122,717

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	TEP
	2011
	Three Months Ended						Three Months Ended				Six Months Ended
	March 31,						June 30,				June 30,
	As			As			As		As		As			As
	Reported			Revised			Reported		Revised		Reported			Revised
	-Thousands of Dollars-
Income Statement
Electric Wholesale Sales	$	35,122		$	35,256		$	31,759	$	31,759	$	67,015		$	67,015
Fuel		71,315			70,370			80,831		80,217		152,138			150,587
Purchased Power		16,601			17,236			26,445		26,444		43,680			43,680
Increase (Decrease) to Reflect PPFAC Recovery Treatment		(9,342	)		(8,937	)		2,112		2,675		(7,671	)		(6,262	)
Income Tax Expense		208			2,528			15,133		15,154		17,624			17,682
Net Income		6,983			4,703			25,128		25,158		29,776			29,861

Balance Sheet
Deferred Income Taxes — Current		36,205			31,985			35,723		34,102		35,723			34,102
Accounts Receivable — Customer		53,560			68,259			76,988		85,471		76,988			85,471
Regulatory Assets — Noncurrent		180,723			176,296			156,345		151,165		156,345			151,165
Common Stock Equity		708,604			715,054			736,916		739,390		736,916			739,390
Accounts Payable — Trade		71,276			70,879			98,251		97,458		98,251			97,458


	UniSource Energy
	2010
	Three Months Ended
	March 31,						June 30,						September 30,						December 31,
	As			As			As			As			As			As			As		As
	Reported			Revised			Reported			Revised			Reported			Revised			Reported		Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	37,064		$	37,092		$	28,466		$	28,467		$	36,776		$	36,838		$	51,579	$	49,565
Fuel		60,448			60,167			69,304			69,151			90,493			89,874			76,793		76,460
Purchased Energy		82,805			82,805			66,591			66,591			93,889			93,889			66,137		64,003
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		(12,631	)		(12,361	)		(10,313	)		(10,164	)		(12,373	)		(11,735	)		4,230		4,638
Other Operations and Maintenance		82,908			82,909			87,134			87,134			88,936			88,936			111,089		111,058
Income Tax Expense		12,435			12,267			15,956			15,958			44,533			43,793			5,000		4,903
Net Income		19,972			20,178			25,886			25,889			54,883			55,665			11,082		11,252
Basic EPS		0.55			0.56			0.71			0.71			1.50			1.52			0.30		0.31
Diluted EPS		0.52			0.52			0.66			0.66			1.36			1.38			0.29		0.30

Balance Sheet
Deferred Income Taxes — Current		51,106			46,948			50,066			45,906			54,705			50,528			32,386		30,822
Accounts Receivable — Customer		69,543			80,005			78,626			91,776			110,014			123,750			91,556		98,333
Regulatory Assets — Noncurrent		145,821			146,847			150,608			152,038			184,097			186,140			196,736		192,966
Common Stock Equity		757,939			766,607			772,833			781,851			816,533			826,334			828,368		830,756
Accounts Payable — Trade		99,936			99,377			107,800			107,461			102,363			101,929			109,896		108,950
Deferred Income Taxes — Noncurrent		233,681			235,197			244,441			246,183			290,772			293,008			246,466		246,466

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	TEP
	2010
	Three Months Ended
	March 31,						June 30,						September 30,						December 31,
	As			As			As			As			As			As			As		As
	Reported			Revised			Reported			Revised			Reported			Revised			Reported		Revised
	-Thousands of Dollars-
Income Statement
Electric Wholesale Sales	$	40,962		$	40,989		$	29,276		$	29,276		$	26,669		$	26,731		$	46,121	$	44,107
Fuel		58,351			58,070			66,753			66,599			85,793			85,174			75,233		74,901
Purchased Power		24,654			24,655			33,337			33,337			47,909			47,909			14,950		12,815
Increase (Decrease) to Reflect PPFAC Recovery Treatment		(3,118	)		(2,847	)		(7,601	)		(7,452	)		(13,362	)		(12,724	)		1,073		1,482
Other Operations and Maintenance		70,365			70,364			74,613			74,613			76,277			74,687			99,096		96,961
Income Tax Expense		6,348			6,245			14,728			14,730			38,139			37,472			1,543		1,489
Net Income		10,349			10,490			27,938			27,941			58,993			59,704			9,999		10,125

Balance Sheet
Deferred Income Taxes — Current		49,881			45,724			50,319			46,159			55,323			51,147			33,640		32,077
Accounts Receivable — Customer		54,957			65,615			63,627			76,777			92,197			105,933			71,425		78,200
Regulatory Assets — Noncurrent		136,013			135,252			140,102			139,671			170,287			170,350			186,074		182,304
Common Stock Equity		666,963			674,551			692,729			700,621			720,063			728,666			707,495		709,884
Accounts Payable — Trade		77,840			77,282			91,606			91,267			81,291			80,856			77,967		77,021
Deferred Income Taxes — Noncurrent		221,098			221,908			230,241			231,247			268,385			269,839			227,615		227,615


	UniSource Energy
	2010
	Six Months Ended						Nine Months Ended						Year Ended
	June 30,						September 30,						December 31,
	As			As			As			As			As			As
	Reported			Revised			Reported			Revised			Reported			Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	65,558		$	65,558		$	100,094		$	102,397		$	151,673		$	151,962
Fuel		129,909			129,318			220,187			219,192			296,980			295,652
Purchased Energy		149,396			149,396			241,151			243,285			307,288			307,288
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		(23,058	)		(22,525	)		(35,335	)		(34,260	)		(31,105	)		(29,622	)
Other Operations and Maintenance		170,042			170,042			258,979			258,979			370,067			370,037
Income Tax Expense		28,201			28,225			73,266			72,018			78,266			76,921
Net Income		46,032			46,067			100,395			101,732			111,477			112,984
Basic EPS		1.27			1.27			2.76			2.80			3.06			3.10
Diluted EPS		1.18			1.18			2.53			2.57			2.82			2.86

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	TEP
	2010
	Six Months Ended						Nine Months Ended						Year Ended
	June 30,						September 30,						December 31,
	As			As			As			As			As			As
	Reported			Revised			Reported			Revised			Reported			Revised
	-Thousands of Dollars-
Income Statement
Electric Wholesale Sales	$	70,265		$	70,265		$	94,694		$	96,997		$	140,815		$	141,103
Fuel		125,260			124,669			210,838			209,843			286,071			284,744
Purchased Power		57,992			57,992			103,766			105,900			118,716			118,716
Increase (Decrease) to Reflect PPFAC Recovery Treatment		(10,833	)		(10,299	)		(24,098	)		(23,023	)		(23,025	)		(21,541	)
Other Operations and Maintenance		144,977			144,977			224,441			219,664			323,537			316,625
Income Tax Expense		20,953			20,975			59,514			58,447			61,057			59,936
Net Income		38,396			38,431			96,979			98,135			106,978			108,260


	UniSource Energy						TEP
	Year Ended
	December 31, 2009
	As			As			As			As
	Reported			Revised			Reported			Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	130,904		$	131,255		$	152,955		$	153,306
Fuel		298,655			296,248			281,710			279,303
Purchased Energy		296,861			296,861			144,528			144,529
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		(17,091	)		(14,553	)		(20,724	)		(18,186	)
Other Operations and Maintenance		333,887			333,579			289,765			282,986
Income Tax Expense		64,348			63,232			55,130			54,220
Net Income		104,258			105,901			89,248			90,688
Basic EPS		2.91			2.95			N/A			N/A
Diluted EPS		2.69			2.73			N/A			N/A

Balance Sheet
Deferred Income Taxes — Current		52,355			48,213			50,789			46,647
Accounts Receivable — Customer		80,191			92,781			62,508			75,099
Regulatory Assets — Noncurrent		147,325			148,319			137,147			136,461
Common Stock Equity		750,865			759,329			643,144			650,591
Accounts Payable — Trade		98,990			98,573			71,328			70,911
Deferred Income Taxes — Noncurrent		227,199			228,596			217,316			218,049


	UniSource Energy				TEP
	Year Ended
	December 31, 2008
	As		As		As		As
	Reported		Revised		Reported		Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	248,855	$	249,195	$	272,411	$	272,750
Fuel		299,987		295,802		289,985		285,799
Purchased Energy		454,765		454,765		250,580		250,580
Other Operations and Maintenance		295,658		295,478		256,584		256,404
Income Tax Expense		16,975		18,747		10,867		12,729
Net Income		14,021		16,955		4,363		7,206
Basic EPS		0.39		0.47		N/A		N/A
Diluted EPS		0.39		0.47		N/A		N/A

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

NOTE 2. REGULATORY MATTERS

ACCOUNTING FOR RATE 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.

PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE (PPFAC) AND PURCHASED GAS ADJUSTMENT (PGA) MECHANISM

TEP’s and UNS Electric’s retail rates include a PPFAC. The PPFAC allows recovery of fuel and purchased power costs, including demand charges, transmission costs, and the prudent costs of contracts for hedging fuel and purchased power. UNS Gas’ retail rates include a PGA mechanism that allows UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor on a per therm basis. For each utility, the cumulative difference between its actual costs and those recovered through the PPFAC/PGA are tracked through the PPFAC/PGA Bank, a balancing account. The PPFAC balances factor into the formulas used to determine the PPFAC rates for TEP and UNS Electric, which are reset annually by the ACC each April for TEP and each June for UNS Electric. UNS Gas’ PGA mechanism is adjusted monthly based on a formula that reflects actual commodity costs over the previous 12 months. UNS Gas is required to request ACC approval of a surcredit if the PGA Bank balance reflects an over-collection of $10 million or more on a billed basis. UNS Gas is also authorized to request ACC approval of a surcharge if its PGA Bank reflects an under-collected balance.

The table below summarizes TEP’s and UNS Electric’s PPFAC surcharge (surcredit) in cents per kWh and UNS Gas’ PGA surcredit in cents per therm:


	2011									2010
	June -			April -						June			April -
	September			May			First Quarter			September			May			First Quarter
TEP
PPFAC		0.53			0.53			0.09			0.09			0.09			0.18
CTC⁽¹⁾		(0.53	)		(0.53	)		(0.09	)		(0.09	)		(0.09	)		(0.18	)

Total PPFAC Rate		—			—			—			—			—			—
UNS Electric		(0.88	)		0.08			0.08			(0.28	)		(1.06	)		(1.06	)
UNS Gas		—			—			—			(8.00	)		(8.00	)		(8.00	)


⁽¹⁾		Competition Transition Charge

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

TEP

TEP offsets the PPFAC surcharge with CTC revenue to be refunded, resulting in a PPFAC rate of zero to customers. After the CTC revenue is fully refunded, which is expected to occur later this year, the PPFAC bank balance could increase until a new PPFAC rate becomes effective in April 2012.

The following table shows the changes in TEP’s PPFAC-related accounts and the effects on revenue and expense:


	At September			At December			Nine Months Ended
	30, 2011			31, 2010			September 30, 2011
									Reduction to
									Fuel and
									Purchased
							Increase to		Power
	Asset (Liability)						Revenue		Expense
	-Millions of Dollars-
PPFAC — Fixed CTC Revenue to be Refunded(current)	$	(5	)	$	(36	)	$	31

PPFAC(current and non-current)		59			54				$	5

For the three months ended September 30, 2011, there was a $16 million increase to revenue and a $1 million increase to fuel and purchased power expense.

PENDING 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 rate increase of 3.8% to cover a revenue deficiency of $5.6 million, and requesting a change in depreciation rates that, if approved, is expected to reduce annual depreciation expense by $1 million. The proposed rates include a higher fixed service charge and a decoupling mechanism, each of which serve to separate the recovery of fixed costs from the level of energy consumed. These changes are intended to provide adequate revenue recovery for declining sales due to the implementation of the state’s energy efficiency standard, which encourages customers to reduce energy consumption.

UNS ELECTRIC PURCHASE OF BMGS

The ACC approved UNS Electric’s purchase of BMGS from UED at book value, subject to FERC approval. FERC approved the sale in June 2011. On July 1, 2011, UNS Electric completed the purchase of BMGS for $63 million. As of July 1, 2011, UNS Electric includes BMGS in rates through a revenue-neutral rate reclassification of approximately 0.7 cents per kWh from base power supply rate to non-fuel base rates.

NOTE 3. BUSINESS SEGMENTS

Based on the way we organize our operations and evaluate performance, we have three reportable segments:

(1)

TEP, a regulated vertically integrated electric utility and UniSource Energy’s largest subsidiary;

(2)

UNS Gas, a regulated gas distribution utility business; and

(3)

UNS Electric, a regulated electric distribution utility business.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

In accordance with accounting rules related to the transfer of a business held under common control, we reflect UNS Electric’s purchase of BMGS as if it occurred on January 1, 2009. The transaction increased UNS Electric’s net income and reconciling adjustments in the table below by $2 million for the three months ended September 30, 2010, and had no impact to the three months ended September 30, 2011. UNS Electric’s net income and reconciling adjustments in the table below increased by $2 million for the nine months ended September 30, 2011, and $4 million for the nine months ended September 30, 2010. The transaction had no impact on UniSource Energy’s consolidated financial statements.

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


	Reportable Segments													UniSource
			UNS			UNS					Reconciling			Energy
	TEP		Gas			Electric		Other			Adjustments			Consolidated
	-Millions of Dollars-
Income Statement
Three Months Ended September 30, 2011:
Operating Revenues — External	$	366	$	17		$	68	$	—		$	—		$	451
Operating Revenues — Intersegment		4		1			—		4			(9	)		—
Income (Loss) Before Income Taxes		88		(1	)		11		—			—			98
Net Income (Loss)		54		(1	)		7		—			—			60

Three Months Ended September 30, 2010:
Operating Revenues — External	$	350	$	17		$	72	$	—		$	—		$	439
Operating Revenues — Intersegment		5		2			1		8			(16	)		—
Income (Loss) Before Income Taxes		97		(2	)		7		(1	)		(2	)		99
Net Income (Loss)		60		(1	)		5		(6	)		(2	)		56

Nine Months Ended September 30, 2011:
Operating Revenues — External	$	894	$	101		$	169	$	1		$	—		$	1,165
Operating Revenues — Intersegment		11		2			2		19			(34	)		—
Income Before Income Taxes		136		10			23		—			(4	)		165
Net Income		84		6			14		—			(2	)		102

Nine Months Ended September 30, 2010:
Operating Revenues — External	$	837	$	99		$	160	$	1		$	—		$	1,097
Operating Revenues — Intersegment		23		4			2		21			(50	)		—
Income (Loss) Before Income Taxes		157		9			20		(6	)		(6	)		174
Net Income (Loss)		98		5			12		(9	)		(4	)		102

When UniSource Energy consolidates its subsidiaries, we have additional significant reconciling adjustments that include the elimination of investments in subsidiaries held by UniSource Energy.


	Reportable Segments
			UNS		UNS
	TEP		Gas		Electric		Other
	-Millions of Dollars-
Intersegment Revenue
Three Months Ended September 30, 2011:
Wholesale Sales — TEP to UNS Electric⁽⁴⁾	$	1	$	—	$	—	$	—
Gas Revenue — UNS Gas to UNS Electric⁽⁵⁾		—		1		—		—
Other Revenue — TEP to Affiliates⁽¹⁾		2		—		—		—
Other Revenue — Millennium to TEP, UNS Gas & UNS Electric⁽²⁾		—		—		—		4
Other Revenue — TEP to UNS Electric⁽³⁾		1		—		—		—

Total Intersegment Revenue	$	4	$	1	$	—	$	4

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	Reportable Segments
			UNS		UNS
	TEP		Gas		Electric		Other
	-Millions of Dollars-
Three Months Ended September 30, 2010:
Wholesale Sales — TEP to UNS Electric⁽⁴⁾	$	2	$	—	$	—	$	—
Wholesale Sales — UNS Electric to TEP⁽⁴⁾		—		—		1		—
Wholesale Sales — UED to UNS Electric⁽⁵⁾		—		—		—		3
Gas Revenue — UNS Gas to UNS Electric⁽⁵⁾		—		2		—		—
Other Revenue — TEP to Affiliates⁽¹⁾		2		—		—		—
Other Revenue — Millennium to TEP, UNS Gas & UNS Electric⁽²⁾		—		—		—		5
Other Revenue — TEP to UNS Electric⁽³⁾		1		—		—		—

Total Intersegment Revenue	$	5	$	2	$	1	$	8


Nine Months Ended September 30, 2011:
Wholesale Sales — TEP to UNS Electric⁽⁴⁾	$	2	$	—	$	—	$	—
Wholesale Sales — UNS Electric to TEP⁽⁴⁾		—		—		2		—
Wholesale Sales — UED to UNS Electric⁽⁵⁾		—		—		—		6
Gas Revenue — UNS Gas to UNS Electric⁽⁵⁾		—		2		—		—
Other Revenue — TEP to Affiliates⁽¹⁾		7		—		—		—
Other Revenue — Millennium to TEP, UNS Gas & UNS Electric⁽²⁾		—		—		—		13
Other Revenue — TEP to UNS Electric⁽³⁾		2		—		—		—

Total Intersegment Revenue	$	11	$	2	$	2	$	19


Nine Months Ended September 30, 2010:
Wholesale Sales — TEP to UNS Electric⁽⁴⁾	$	15	$	—	$	—	$	—
Wholesale Sales — UNS Electric to TEP⁽⁴⁾		—		—		2		—
Wholesale Sales — UED to UNS Electric⁽⁵⁾		—		—		—		8
Gas Revenue — UNS Gas to UNS Electric⁽⁵⁾		—		4		—		—
Other Revenue — TEP to Affiliates⁽¹⁾		6		—		—		—
Other Revenue — Millennium to TEP, UNS Gas & UNS Electric⁽²⁾		—		—		—		13
Other Revenue — TEP to UNS Electric⁽³⁾		2		—		—		—

Total Intersegment Revenue	$	23	$	4	$	2	$	21


⁽¹⁾		Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.

⁽²⁾		Millennium provides a supplemental workforce and meter-reading services to TEP, UNS Gas and UNS Electric. Millennium bases the charges on the costs of services performed. Management believes the charges are reasonable for the services rendered.

⁽³⁾		TEP charges UNS Electric for control area services based on a FERC-approved tariff.

⁽⁴⁾		TEP and UNS Electric sell power to each other at prices based on the Dow Jones Four Corners Daily Index.

⁽⁵⁾		Transactions between non-registrant wholly-owned subsidiaries that eliminate in consolidation.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

NOTE 4. DEBT AND CREDIT FACILITIES

We have summarized below the significant changes to our debt from those reported in our 2010 Annual Report on Form 10-K. There have been no significant changes to our outstanding letters of credit.

UNISOURCE ENERGY CREDIT AGREEMENT

UniSource Energy had $71 million in borrowings outstanding as of September 30, 2011 and $27 million in borrowings outstanding as of December 31, 2010, under its revolving credit facility. The revolving loan balances are included in Long-Term Debt in the balance sheet.

TEP DEBT

TEP had $5 million in borrowings outstanding under the TEP Credit Agreement as of September 30, 2011. TEP had no borrowings outstanding under the TEP Credit Agreement as of December 31, 2010. The revolving loan balances are included in Current Liabilities in the balance sheets.

UNS ELECTRIC TERM LOAN CREDIT AGREEMENT

In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.25%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four-year period ending August 10, 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt in the balance sheet, is guaranteed by UES.

The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio, and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement.

UNS GAS SENIOR GUARANTEED NOTES

In August 2011, UNS Gas issued $50 million of senior guaranteed notes at 5.39%, due August 2026. UNS Gas used the proceeds to pay in full the $50 million of UNS Gas 6.23% notes that matured in August 2011. UNS Gas notes are guaranteed by UES. The UNS Gas notes are included in Long-Term Debt in the balance sheet.

UNS Gas capitalized $0.4 million of costs related to the issuance of the notes and will amortize these costs over the life of the notes.

The note purchase agreements contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens on secure indebtedness, restricted payments, and incurrence of indebtedness. UNS Gas must meet an interest coverage ratio and a maximum leverage ratio to issue additional debt and pay dividends. However, UNS Gas may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million.

UED SECURED TERM LOAN

In July 2011, UED received $63 million from UNS Electric for the sale of BMGS. UED used a portion of those funds to fully repay the $27 million outstanding under its secured term loan.

COVENANT COMPLIANCE

As of September 30, 2011, UniSource Energy and its subsidiaries were in compliance with the terms of their respective loan and credit agreements and no amounts of net income were subject to dividend restrictions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

NOTE 5. INCOME TAXES

For the three and nine months ended September 30, 2011 and September 30, 2010, the effective tax rate differed from the federal rate, primarily due to state income taxes. In addition, the effective rate for the three and nine months ended September 30, 2010, was impacted by the domestic production activities deduction, deferred tax asset write-offs, and valuation allowance adjustments relating to Millennium’s investments.

Deferred Tax Write-Offs and Valuation Allowance

For the three months ended September 30, 2010, UniSource Energy recorded a $3 million out-of-period income tax expense. The out-of-period expense related to the write-off of a previously recorded deferred tax asset associated with the excess of tax over book basis in a consolidated Millennium investment. Management concluded that this out-of-period adjustment was not material to the current and prior period financial statements.

For the nine months ended September 30, 2010, UniSource Energy recorded a $6 million valuation allowance against capital loss deferred tax assets. If capital losses remain unused after the 5-year carryforward period, they expire. A valuation allowance was recorded because management does not anticipate that UniSource Energy will generate future capital gains prior to the expiration date of the capital loss carryforward.

State Tax Rate Change

We record deferred tax assets and liabilities using expected income tax rates when the deferred tax assets and liabilities are realized or settled. In the first quarter of 2011, the Arizona legislature passed a bill reducing the corporate income tax rate from the current rate of 6.968%. The tax rate reduction will be phased in beginning in 2014, with a reduction of approximately 0.5% per year until the income tax rate reaches 4.9% for 2017 and later years. As a result of these tax rate reductions, we reduced the net deferred tax liabilities at UniSource Energy and TEP by $13 million, offset entirely by adjustments to regulatory assets and liabilities. The income tax rate change will not have an impact on UniSource Energy’s and TEP’s effective tax rate for 2011.

Uncertain Tax Positions

As a result of a change in accounting method approved by the Internal Revenue Service in the second quarter of 2011, the balance of unrecognized tax benefits decreased by $13 million for UniSource Energy and $10 million for TEP. As a result of settlements with taxing authorities and the expiration of the statue of limitations for 2007, the balance of unrecognized tax benefits decreased an additional $9 million in the third quarter of 2011 for UniSource Energy and TEP. The decrease in unrecognized tax benefits resulted in a $1 million decrease to interest expense but had no impact on income tax expense. The adjustment decreased Other in Deferred Credits and Other Liabilities and increased Deferred Income Taxes — Noncurrent on the balance sheet.

NOTE 6. COMMITMENTS, CONTINGENCIES AND PROPOSED ENVIRONMENTAL MATTERS

UNISOURCE ENERGY AND TEP COMMITMENTS

Through September 2011, UniSource Energy has spent $59 million to acquire land and develop a new headquarters building in downtown Tucson. UniSource Energy has a remaining commitment of $10 million at September 30, 2011. UniSource Energy expects to sell the land and building to TEP at cost in November 2011. TEP expects to complete the building in the fourth quarter of 2011.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

TEP COMMITMENTS

In 2011, TEP entered into the following new long-term purchase commitments in addition to those reported in our 2010 Annual Report on Form 10-K:


	Purchase Commitments
	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Coal⁽¹⁾	$	34	$	40	$	14	$	14	$	—	$	—	$	102
Transportation⁽²⁾		3		4		4		4		4		8		27
Purchased Power⁽³⁾		3		23		20		21		12		196		275
Solar Equipment⁽⁴⁾		12		12		12		—		—		—		36

Total	$	52	$	79	$	50	$	39	$	16	$	204	$	440


⁽¹⁾		TEP executed a new coal supply agreement and amended an existing coal supply agreement in March 2011, incurring minimum purchase obligations.

⁽²⁾		TEP executed a new transportation agreement requiring minimum annual transport quantities of 2.4 million tons of coal to its Springerville Generating Station from July 1, 2011 through December 2017.

⁽³⁾		Purchased Power includes contracts that will settle in June 2012 through September 2014 with prices per MWh that are indexed to natural gas prices. TEP’s estimated minimum payment obligation for these purchases is based on projected market prices as of September 30, 2011. Additionally, Purchased Power includes two long-term Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011. TEP is obligated to purchase 100% of the output from these facilities. The table above includes estimated future payments based on expected power deliveries through 2031. TEP has entered into additional long-term renewable PPAs to comply with the RES requirements; however, TEP’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

⁽⁴⁾		TEP has a commitment to purchase 9 MW of photovoltaic equipment through December 2013. 3 MW were approved by the ACC, and 6 MW remain subject to ACC approval, which is expected in the fourth quarter of 2011.

UNS ELECTRIC COMMITMENTS

In 2011, UNS Electric entered into the following new long-term, forward power purchase commitments in addition to those reported in our 2010 Annual Report on Form 10-K.


	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Purchased Power⁽¹⁾	$	1	$	20	$	24	$	35	$	3	$	46	$	129


⁽¹⁾		Purchased power includes contracts that will settle in October 2011 through December 2014 at fixed prices per MWh or at prices indexed to natural gas prices. UNS Electric’s estimated minimum payment obligation for these purchases is based on projected market prices as of September 30, 2011. Purchased power commitments also include one long-term PPA with a renewable energy generation facility that achieved commercial operation in September 2011. UNS Electric is obligated to purchase 100% of the output from this facility. The table above includes estimated future payments based on expected power deliveries through 2031.

UNS GAS COMMITMENTS

In 2011, UNS Gas entered into new long-term purchase commitments for fuel in addition to those reported in our 2010 Annual Report on Form 10-K. These contracts will settle in January 2012 through July 2014 at fixed prices per MMBtu. UNS Gas’ minimum payment obligation for these purchases is $3 million in both 2012 and 2013 and $2 million in 2014.

TEP CONTINGENCIES

Settlement of El Paso Electric Dispute

In April 2011, TEP and El Paso entered into a settlement agreement, subject to approval by the FERC, to resolve a dispute over transmission service from Luna to TEP’s system. The dispute that originated in 2006 under the 1982 Power Exchange and Transmission Agreement between the parties (Exchange Agreement). In 2008, the FERC issued an order supporting TEP’s position in the dispute. El Paso subsequently appealed that order. In December 2008, El Paso refunded $11 million, including interest, to TEP for transmission service from Luna to TEP’s system from 2006 to 2008.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

The settlement reduces TEP’s rights for transmission under the Exchange Agreement from 200 MW to 170 MW and requires TEP to pay El Paso a lump-sum of $5 million, equivalent to the total amount that TEP would have paid El Paso for 30 MW of transmission from February 1, 2006, through the settlement date, including interest. Under the PPFAC mechanism, TEP is allowed to recover $2 million of this additional transmission expense from its customers. In accordance with the settlement agreement, TEP has entered into two new firm transmission service agreements under El Paso’s Open Access Transmission Tariff for a total of 40 MW. The settlement agreement also requires El Paso to withdraw its appeal before the United States Court of Appeals District of Columbia Circuit and requires TEP to withdraw its related complaint before the Arizona District of the United States District Court.

The settlement agreement was filed with the FERC in June 2011, and becomes effective after: 1) issuance by the FERC of a final non-appealable order approving the settlement, and 2) issuance by the FERC of a final non-appealable order approving a settlement between El Paso and Macho Springs Power I, LLC regarding the reimbursement of network upgrade costs associated with the interconnection of the Macho Springs wind facility to the El Paso system. TEP has agreed to purchase Macho Springs’ output through a 20-year PPA and expects to begin receiving power from the facility in the fourth quarter of 2011. The settlement agreements were both approved by the FERC in August 2011 which approvals became final and non-appealable on September 30, 2011. By its terms, the TEP settlement agreement is effective November 1, 2011.

As a result, TEP recognized a pre-tax gain of approximately $7 million, including interest, in the third quarter of 2011. To reflect the gain, TEP recorded a $7.1 million net reduction to Transmission Expense, $0.9 million of Interest Income, and $0.6 million of Interest Expense on the Income Statement.

Claims Related to Navajo Generating Station

In June 1999, the Navajo Nation filed suit in the U.S. District Court for the District of Columbia (D.C. Lawsuit) against parties including SRP; several Peabody Coal Company entities including Peabody Western Coal Company (Peabody), the coal supplier to Navajo Generating Station (Navajo); Southern California Edison Company (SCE); and other defendants. Although TEP is not a named defendant in the D.C. Lawsuit, TEP owns 7.5% of Navajo Units 1, 2 and 3. The D.C. Lawsuit alleged, among other things, that the defendants obtained a favorable coal royalty rate on the lease agreements under which Peabody mines coal by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The suit initially sought $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease.

In July 2001, the District Court dismissed all claims against SRP. In April 2010, the Navajo Nation filed a Second Amended Complaint which dropped the treble damages claim. In August 2011, the Navajo Nation, Peabody, SCE and SRP executed a written settlement agreement in return for the Navajo Nation’s dismissal of all claims in the D.C. Lawsuit. SRP has asked that the Navajo participants, including TEP, contribute toward the settlement based on its 7.5% ownership interest in the Navajo plant. TEP will pay SRP the requested contribution which will not have a material impact on TEP’s financial statements.

In 2004, Peabody filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP, for reimbursement of royalties and other costs arising out of the D.C. Lawsuit. In July 2008, the parties entered into a joint stipulation of dismissal of these claims which was approved by the Circuit Court. TEP does not believe the lawsuit will be re-filed based upon the final outcome of the D.C. Lawsuit.

Claims Related to San Juan Generating Station

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 PNM, as operator of San Juan; PNM’s parent PNM Resources, Inc. (PNMR); San Juan Coal Company (SJCC), which operates the San Juan mine that supplies coal to San Juan; and SJCC’s parent BHP Minerals International Inc. (BHP). The Sierra Club alleges 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 constitute “open dumping” in violation of RCRA. The RCRA claims are asserted against PNM, PNMR, SJCC and

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

BHP. The suit also includes claims under SMCRA which are directed only against SJCC and BHP. The suit seeks 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. With the agreement of the parties, the court entered a stay of the action in August 2010, to allow the parties to try to address the Sierra Club’s concerns. If the parties are unable to settle the matter, PNM has indicated that it plans an aggressive defense of the RCRA claims in the suit. TEP cannot predict the outcome of this matter and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought, an estimate of the range of loss cannot be determined at this time.

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 cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

TEP owns 50% of San Juan Units 1 and 2, which represents approximately 20% of the total generation capacity of the entire San Juan Generating Station, and is responsible for its share of any resulting liabilities.

San Juan Mine Fire

In September 2011, there was a fire at the underground mine that provides coal for San Juan. In October 2011, SJCC indicated that mining operations could restart in April 2012.

PNM estimates that the current inventory of mined coal could supply the fuel requirements of San Juan for approximately eight and one-half months at forecasted consumption levels. Based on information we have received to date, TEP does not expect the mine fire to have a material effect on its financial condition, results of operations, or cash flows due to the inventories of previously mined coal available to supply San Juan. However, if the mine is shut down longer than currently anticipated, the owners of San Juan would need to consider alternatives for operating the unit, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers through the PPFAC, subject to ACC approval.

Claims Related to Four Corners Generating Station

On May 7, 2010, APS received a Notice of Intent to Sue from EarthJustice (the Notice), on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at the Four Corners Generating Station (Four Corners). The Notice alleges New Source Review-related violations and New Source Performance Standards (NSPS) violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA’s lawsuit, if it so desires. The 60-day period lapsed in early July 2010, and the EPA did not take any action. In September 2011, APS received a second Notice of Intent to Sue from EarthJustice, on behalf of the same environmental organizations (the Second Notice). The Second Notice is virtually identical to the May 2010 Notice and alleges violations of the New Source Review and NSPS programs.

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 APS and the other Four Corners participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. TEP is evaluating the lawsuit and cannot currently predict the outcome of the proceeding and, due to the general and non-specific nature of the claim and the indeterminate scope and nature of the injunctive relief sought, an estimate of the range of loss cannot be determined at this time.

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

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 these mines. TEP’s share of the reclamation costs for coal supply agreements expiring in 2016 through 2019 is approximately $26 million. TEP recognizes this cost over the remaining terms of these coal supply agreements and had recorded liabilities of $13 million at September 30, 2011, and $11 million at December 31, 2010.

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 agreement 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 TEP to pass through most fuel costs (including final reclamation costs) to customers. Therefore, TEP classifies these costs as a regulatory asset. TEP will increase the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements on an accrual basis and recover the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile transmission line from Tucson 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 UniSource Energy purchased the electric system in Nogales and surrounding Santa Cruz County from Citizens Utilities 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. TEP and UNS Electric are considering options for the project, including potential new routes. If a decision is made to pursue an alternative route, approvals will be needed from the ACC, the Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and Water Commission. As of September 30, 2011 and December 31, 2010, TEP had capitalized $11 million related to the project, including $2 million to secure land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes cost recovery is probable for prudent and reasonably incurred costs related to the project as a consequence of the ACC’s requirement for a second transmission line serving the Nogales, Arizona area.

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. The EPA is required to develop rules establishing standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units and to issue final rules by November 2011.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

Navajo

Based on the EPA’s proposed 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.

Springerville

Based on the EPA’s proposed standards, mercury emission control equipment may be required at 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 proposed federal standards.

Sundt

TEP does not anticipate the proposed EPA rule will have a material capital impact on Sundt Unit 4.

Four Corners

TEP is analyzing the potential effect of the proposed EPA rule on Four Corners.

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 therefore oversees regional haze planning for these plants.

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. TEP cannot predict the ultimate outcome of these matters.

San Juan

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO₂ and sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (SCR) technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions. Based on two recent cost analyses commissioned by PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $155 million and $202 million.

In September 2011, PNM filed a petition to review the EPA FIP with the 10th Circuit Court of Appeals challenging the EPA’s cost analysis used to determine the BART, the visibility analysis used to justify SCRs, and various other legal aspects of the order. Also in September 2011, PNM filed with the EPA a request to stay the five-year installation timeframe ordered by the FIP until the 10th Circuit has had time to consider and rule on the petition to review. PNM filed a Petition for Reconsideration of the rule and a Request to Stay the effective date of the final BART FIP under the CAA with the EPA in October 2011. Neither the Petition in the 10^th Circuit, nor the Petition for Reconsideration by the EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted leave to intervene in that appeal. WildEarth Guardians, Dine Citizens against Ruining our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance and Sierra Club sought, and were granted leave to intervene in PNM’s petition to review in the 10^th Circuit. Additionally, in October 2011, Governor Susana Martinez of New Mexico and the New Mexico Environment Department filed a Petition for Review of the EPA’s final FIP determination in the 10^th Circuit and a Petition for Reconsideration of the rule with the EPA.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

Four Corners

In February 2011, the EPA supplemented the proposed FIP for the BART at Four Corners that would require the installation of SCR on Units 4 and 5. TEP’s estimated share of the capital costs to install SCR is approximately $35 million. Once the EPA finalizes the BART rule for Four Corners, the plant’s participants would have until 2018 to achieve compliance.

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report being commissioned by the Department of Interior. The report will address potential energy, environmental and economic issues associated with regional haze rule compliance at Navajo. That report is due in December 2011. A final BART rule is expected in 2012. If the EPA determines that 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 costs is 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

NOTE 7. EMPLOYEE BENEFIT PLANS

COMPONENTS OF NET PERIODIC BENEFIT COST

The components of UniSource Energy’s net periodic benefit cost were as follows:


							Other Postretirement
	Pension Benefits						Benefits
	Three Months Ended						Three Months Ended
	September 30,						September 30,
	2011			2010			2011		2010
	-Millions of Dollars-

Components of Net Periodic Benefit Cost
Service Cost	$	2		$	2		$	1	$	—
Interest Cost		4			4			1		1
Expected Return on Plan Assets		(4	)		(3	)		—		—
Amortization of Net Loss		2			1			—		—

Net Periodic Benefit Cost	$	4		$	4		$	2	$	1

The table above includes pension benefit costs of less than $0.5 million and other postretirement benefit costs of less than $0.1 million for UNS Gas and UNS Electric. The remaining cost relates to TEP.


							Other Postretirement
	Pension Benefits						Benefits
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	-Millions of Dollars-

Components of Net Periodic Benefit Cost
Service Cost	$	7		$	6		$	2		$	2
Interest Cost		12			11			3			3
Expected Return on Plan Assets		(12	)		(10	)		—			—
Amortization of Prior Service Costs		—			—			(1	)		(1	)
Amortization of Net Loss		5			4			—			—

Net Periodic Benefit Cost	$	12		$	11		$	4		$	4

The table above includes pension benefit costs of $1 million and other postretirement benefit costs of less than $0.1 million for UNS Gas and UNS Electric. The remaining cost relates to TEP.

NOTE 8. SHARE-BASED COMPENSATION PLANS

In May 2011, UniSource Energy shareholders approved the UniSource Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), a new share-based compensation plan. The total number of shares which may be awarded under the 2011 Plan cannot exceed 1.2 million shares. The 2011 Plan supersedes all prior equity compensation plans (Prior Plans). The Prior Plans, however, remain in effect until all stock options and other awards granted thereunder have been exercised, forfeited, canceled, expired or terminated.

RESTRICTED STOCK UNITS AND PERFORMANCE SHARES

Restricted Stock Units

In May 2011, the Compensation Committee of the UniSource Energy Board of Directors granted 14,655 restricted stock units to non-employee directors at a grant date fair value of $37.53 per share. The restricted stock units vest in one year or immediately upon death, disability, or retirement. We recognize compensation expense equal to fair market value on the grant date 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 recipient is no longer a director, common stock shares will be issued for the vested stock units.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

Performance Shares

In March 2011, the Compensation Committee granted 80,440 performance share awards to officers. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $33.73 per share. Those awards will be paid out in shares of UniSource Energy Common Stock based on a comparison of UniSource Energy’s cumulative Total Shareholder Return to that of the Edison Electric Institute Index during the performance period of January 1, 2011 through December 31, 2013. The remaining half had a grant date fair value of $36.58 per share and will be paid out in shares of UniSource Energy Common Stock based on cumulative net income for the three-year period ending December 31, 2013. The performance shares vest based on the achievement of 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

UniSource Energy and TEP recorded share-based compensation expense of less than $1 million for the three months ended September 30, 2011 and 2010. For the nine months ended September 30, 2011 and 2010, UniSource Energy and TEP recorded share-based compensation expense of $2 million.

At September 30, 2011, the total unrecognized compensation cost related to non-vested share-based compensation was $2 million. This amount will be recorded as compensation expense over the remaining vesting periods through December 2013. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at September 30, 2011, was 1 million.

NOTE 9. FAIR VALUE MEASUREMENTS

The following tables set forth, by level within the fair value hierarchy, UniSource 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.


	UniSource Energy
	September 30, 2011
	Quoted Prices
	in		Significant
	Active Markets		Other			Significant
	for Identical		Observable			Unobservable
	Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	-Millions of Dollars-
Assets
Cash Equivalents⁽¹⁾	$	33	$	—		$	—		$	33
Rabbi Trust Investments to support the Deferred
Compensation and SERP Plans⁽²⁾		—		16			—			16
Energy Contracts⁽⁴⁾		—		1			13			14

Total Assets		33		17			13			63


Liabilities
Energy Contracts⁽⁴⁾		—		(12	)		(23	)		(35	)
Interest Rate Swaps⁽⁵⁾		—		(12	)		—			(12	)

Total Liabilities		—		(24	)		(23	)		(47	)

Net Total Assets and (Liabilities)	$	33	$	(7	)	$	(10	)	$	16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	UniSource Energy
	December 31, 2010
	Quoted Prices
	in		Significant
	Active Markets		Other			Significant
	for Identical		Observable			Unobservable
	Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	-Millions of Dollars-
Assets
Cash Equivalents⁽¹⁾	$	38	$	—		$	—		$	38
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans⁽²⁾		—		16			—			16
Collateral Posted⁽³⁾		—		3			—			3
Energy Contracts⁽⁴⁾		—		—			15			15

Total Assets		38		19			15			72


Liabilities
Energy Contracts⁽⁴⁾		—		(19	)		(25	)		(44	)
Interest Rate Swaps⁽⁵⁾		—		(10	)		—			(10	)

Total Liabilities		—		(29	)		(25	)		(54	)

Net Total Assets and (Liabilities)	$	38	$	(10	)	$	(10	)	$	18


	TEP
	September 30, 2011
	Quoted Prices
	in		Significant
	Active Markets		Other			Significant
	for Identical		Observable			Unobservable
	Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	-Millions of Dollars-
Assets
Cash Equivalents⁽¹⁾	$	14	$	—		$	—		$	14
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans⁽²⁾		—		16			—			16
Energy Contracts⁽⁴⁾		—		—			3			3

Total Assets		14		16			3			33


Liabilities
Energy Contracts⁽⁴⁾		—		(4	)		(2	)		(6	)
Interest Rate Swaps⁽⁵⁾		—		(12	)		—			(12	)

Total Liabilities		—		(16	)		(2	)		(18	)

Net Total Assets and (Liabilities)	$	14	$	—		$	1		$	15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	TEP
	December 31, 2010
	Quoted Prices
	in		Significant
	Active Markets		Other			Significant
	for Identical		Observable			Unobservable
	Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	-Millions of Dollars-
Assets
Cash Equivalents⁽¹⁾	$	21	$	—		$	—		$	21
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans⁽²⁾		—		16			—			16
Energy Contracts⁽⁴⁾		—		—			3			3

Total Assets		21		16			3			40


Liabilities
Energy Contracts⁽⁴⁾		—		(7	)		(2	)		(9	)
Interest Rate Swaps⁽⁵⁾		—		(10	)		—			(10	)

Total Liabilities		—		(17	)		(2	)		(19	)

Net Total Assets and (Liabilities)	$	21	$	(1	)	$	1		$	21


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

(3)		Collateral provided for energy contracts with counterparties to reduce credit risk exposure. Collateral posted is included in Current Assets — Other in the UniSource Energy balance sheet.

(4)		Energy Contracts include gas swap agreements (Level 2), 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 in the UniSource Energy and TEP balance sheets. We describe the valuation techniques below. See Note 14.

(5)		We value interest rate swaps based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association (SIFMA) Municipal Swap index. These interest rate swaps are included in Derivative Instruments in the UniSource Energy and TEP balance sheets.

Energy Contracts

TEP, UNS Gas and UNS Electric 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 (NYMEX) pricing, adjusted for basis differences — we categorize the instrument in Level 2. We categorize derivatives in Level 3 using an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices, TEP and UNS Electric obtain quotes from brokers, major market participants, exchanges or industry publications and rely on their 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 including: delivery periods during non-standard time blocks, delivery during only a few months of a given year when prices are quoted only for the annual average, or delivery at illiquid delivery points. In these cases, we use percentage multipliers to value non-standard time blocks, we apply historical price curve relationships to calendar year quotes, and we include adjustments for transmission and line losses to value contracts at illiquid delivery points. 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 market credit default swap data. We review these assumptions quarterly.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

TEP estimates the fair value of its purchase power call option using an internal pricing model which includes assumptions about market risks such as liquidity, volatility, and contract valuation. This model also considers credit and non-performance risk.

UniSource Energy’s and TEP’s assessments of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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


	UniSource
	Energy			TEP
	Three Months Ended
	September 30, 2011
	Energy Contracts
	-Millions of Dollars-
Balance as of June 30, 2011	$	(9	)	$	1
Gains (Losses) Realized/Unrealized
Recorded to Net Regulatory Assets — Derivative Instruments		(3	)		1
Settlements		2			(1	)

Balance as of September 30, 2011	$	(10	)	$	1

Total Gains (Losses) Attributable to the Change in Unrealized Gains or Losses Relating to Assets/Liabilities Held at the End of the Period	$	(3	)	$	1


	UniSource
	Energy			TEP
	Nine Months Ended
	September 30, 2011
	Energy Contracts
	-Millions of Dollars-
Balance as of December 31, 2010	$	(10	)	$	1
Gains (Losses) Realized/Unrealized
Recorded to:
Net Regulatory Assets — Derivative Instruments		(6	)		2
Other Comprehensive Income		(1	)		(1	)
Settlements		7			(1	)

Balance as of September 30, 2011	$	(10	)	$	1

Total Gains (Losses) Attributable to the Change in Unrealized Gains or Losses Relating to Assets/Liabilities Held at the End of the Period	$	(6	)	$	1

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	UniSource Energy								TEP
	Three Months Ended
	September 30, 2010
	Energy			Equity					Energy
	Contracts			Investments⁽¹⁾		Total			Contracts
	-Millions of Dollars-
Balance as of June 30, 2010	$	(11	)	$	1	$	(10	)	$	2
Gains (Losses) Realized/Unrealized
Recorded to:
Net Regulatory Assets — Derivative Instruments		(6	)		—		(6	)		2
Other Comprehensive Income		(1	)		—		(1	)		(1	)
Settlements		4			—		4			(1	)

Balance as of September 30, 2010	$	(14	)	$	1	$	(13	)	$	2

Total Gains (Losses) Attributable to the Change in Unrealized Gains or Losses Relating to Assets/Liabilities Held at the End of the Period	$	(6	)	$	—	$	(6	)	$	1


	UniSource Energy									TEP
	Nine Months Ended
	September 30, 2010
	Energy			Equity						Energy
	Contracts			Investments⁽¹⁾			Total			Contracts
	-Millions of Dollars-
Balance as of December 31, 2009	$	(13	)	$	6		$	(7	)	$	(4	)
Gains (Losses) Realized/Unrealized
Recorded to:
Net Regulatory Assets — Derivative Instruments		(10	)		—			(10	)		10
Other Comprehensive Income		(3	)		—			(3	)		(3	)
Other Expense		—			(5	)		(5	)		—
Settlements		12			—			12			(1	)

Balance as of September 30, 2010	$	(14	)	$	1		$	(13	)	$	2

Total Gains (Losses) Attributable to the Change in Unrealized Gains or Losses Relating to Assets/Liabilities Held at the End of the Period	$	(7	)	$	—		$	(7	)	$	6


(1)		In December 2010, Millennium reduced to zero the book value of its equity investments classified as Level 3 in the fair value hierarchy.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

Financial Instruments Not Carried at Fair Value

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

•

The carrying amounts of our current assets and liabilities, including Current Maturities of Long-Term Debt, and amounts outstanding under our credit agreements approximate their fair value due to the short-term nature of these instruments. These items have been excluded from the table below.

•

Investments in Lease Debt and Equity: TEP calculates the present value of remaining cash flows at the balance sheet date using current market rates for instruments with similar characteristics with respect to credit rating and time-to-maturity. We also incorporate the impact of counterparty credit risk using market credit default swap data.

•

Long-Term Debt: UniSource Energy and TEP use quoted market prices, where available, or calculate the present value of remaining cash flows at the balance sheet date using current market rates for bonds with similar characteristics with respect to credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of their fair value. We also incorporate the impact of our own credit risk using a credit default swap rate when determining the fair value of long-term debt.

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


	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	-Millions of Dollars-
Assets:
TEP Investments in Lease Debt and Equity	$	66	$	75	$	105	$	112
Liabilities:
Long-Term Debt
TEP		1,004		935		1,004		866
UniSource Energy		1,455		1,431		1,353		1,243

NOTE 10. UNISOURCE ENERGY EARNINGS PER SHARE

We compute basic 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 and common shares that would result from the conversion of convertible 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 notes were converted to common shares.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

The following table shows the effects of potentially dilutive common stock on the weighted average number of shares:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	-Thousands of Dollars-
Numerator:
Net Income	$	59,712	$	55,665	$	101,787	$	101,732
Income from Assumed Conversion of Convertible Senior Notes		1,097		1,097		3,292		3,292

Adjusted Numerator	$	60,809	$	56,762	$	105,079	$	105,024


	-Thousands of Shares-
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued		36,867		36,308		36,739		36,107
Fully Vested Deferred Stock Units		136		132		127		120
Participating Securities		50		93		64		94

Total Weighted Average Shares of Common Stock Outstanding and Participating Securities — Basic		37,053		36,533		36,930		36,321
Effect of Dilutive Securities:
Convertible Senior Notes		4,295		4,192		4,268		4,166
Options and Stock Issuable under Share Based Compensation Plans		429		416		379		436

Total Shares — Diluted		41,777		41,141		41,577		40,923

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

Three Months Ended

Nine Months Ended

September 30,

2011

2010

2011

2010

-Thousands of Shares-

Stock Options Excluded from the Diluted EPS Computation

147

218

158

227

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

NOTE 11. STOCKHOLDERS’ EQUITY

In August 2011, UED and Millennium each paid dividends of $3 million to UniSource Energy, which represented the return of capital distributions.

In July 2011, UES contributed $20 million of capital to UNS Electric, using a $20 million capital contribution that UES received from UniSource Energy.

In July 2011, UED paid UniSource Energy a dividend of $36 million, $25 million of which represented a return of capital. In February 2010, UED paid UniSource Energy a dividend of $9 million, $4 million of which represented a return of capital.

In both February 2011 and in April 2010, UES paid a dividend of $10 million to UniSource Energy, using dividend funds received from UNS Gas. During the quarter ended March 31, 2010, Millennium paid UniSource Energy dividends of $6 million, representing the return of capital distributions.

In March 2010, UniSource Energy contributed $15 million of capital to TEP.

NOTE 12. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The following recently issued accounting standards are not yet reflected in UniSource Energy’s and TEP’s financial statements:

•

The Financial Accounting Standards Board (FASB) issued authoritative guidance that will eliminate the current option to report other comprehensive income in the statement of changes in equity. An entity can elect to present items of net income and other comprehensive income in one continuous statement, or in two separate but consecutive statements. We will be required to comply in the first quarter of 2012. We are evaluating which presentation method to use.

•

The FASB issued authoritative guidance that changed some fair value measurement principles and disclosure requirements. The most significant disclosure change is expansion of required information for unobservable inputs. We will be required to comply in the first quarter of 2012, and we do not expect this pronouncement to have a material impact on the valuation techniques used to estimate the fair value of assets and liabilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

NOTE 13. SUPPLEMENTAL CASH FLOW INFORMATION

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


	UniSource Energy
	Nine Months Ended
	September 30,
	2011			2010
	-Thousands of Dollars-

Net Income	$	101,787		$	101,732
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities:
Depreciation Expense		99,653			95,773
Amortization Expense		22,513			20,797
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		4,513			4,025
Amortization of Deferred Debt-Related Costs Included in Interest Expense		3,185			2,672
Provision for Retail Customer Bad Debts		1,305			2,881
Use of Renewable Energy Credits for Compliance		4,669			—
Deferred Income Taxes		77,741			57,722
Deferred Tax Valuation Allowance		(73	)		5,702
Pension and Postretirement Expense		15,903			14,626
Pension and Postretirement Funding		(25,998	)		(20,927	)
Allowance for Equity Funds Used During Construction		(3,516	)		(2,780	)
Share-Based Compensation Expense		2,025			2,102
Excess Tax Benefit from Stock Options Exercised		(29	)		(1,796	)
CTC Revenue Refunded		(30,652	)		(8,152	)
Decrease to Reflect PPFAC/PGA Recovery Treatment		(5,174	)		(34,260	)
Gain on Settlement of El Paso Electric Dispute		(7,391	)		—
Loss on Millennium’s Investments		—			5,208
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately:
Accounts Receivable		(22,495	)		(36,929	)
Materials and Fuel Inventory		(195	)		12,691
Accounts Payable		9,507			6,834
Income Taxes		(11,870	)		4,724
Interest Accrued		(3,063	)		(3,633	)
Taxes Other Than Income Taxes		17,048			18,855
Other		11,094			7,666

Net Cash Flows — Operating Activities	$	260,487		$	255,533

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited


	TEP
	Nine Months Ended
	September 30,
	2011			2010
	-Thousands of Dollars-

Net Income	$	83,773		$	98,135
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities:
Depreciation Expense		78,124			74,143
Amortization Expense		25,282			23,963
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		3,280			2,837
Amortization of Deferred Debt-Related Costs Included in Interest Expense		1,866			1,534
Provision for Retail Customer Bad Debts		942			1,961
Use of Renewable Energy Credits for Compliance		4,280			—
Deferred Income Taxes		66,090			48,916
Pension and Postretirement Expense		14,113			12,979
Pension and Postretirement Funding		(23,453	)		(19,174	)
Share-Based Compensation Expense		1,580			1,628
Allowance for Equity Funds Used During Construction		(2,980	)		(2,340	)
CTC Revenue Refunded		(30,652	)		(8,152	)
Decrease to Reflect PPFAC Recovery Treatment		(5,146	)		(23,023	)
Gain on Settlement of El Paso Electric Dispute		(7,391	)		—
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately:
Accounts Receivable		(35,481	)		(45,706	)
Materials and Fuel Inventory		144			11,889
Accounts Payable		16,030			13,774
Income Taxes		(13,792	)		(2,186	)
Interest Accrued		1,685			1,420
Taxes Other than Income Taxes		16,541			17,772
Other		10,709			10,541

Net Cash Flows — Operating Activities	$	205,544		$	220,911

NOTE 14. ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES

RISKS AND OVERVIEW

TEP, UNS Gas and UNS Electric are exposed to energy price risk associated with their gas and purchased power requirements, volumetric risk associated with their seasonal load, and operational risk associated with their power plants, transmission and transportation systems. TEP, UNS Gas and UNS Electric reduce their energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability; ensuring the companies can meet their load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Note 2.

We 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.

We present cash collateral and derivative assets and liabilities associated with the same counterparty separately in our financial statements, and we bifurcate all derivatives into their current and long-term portions on the balance sheet.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

DERIVATIVES POLICY

We have not made 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, 2010.

FINANCIAL IMPACT OF DERIVATIVES

Cash Flow Hedges

UNS Electric entered into a cash flow hedge in August 2011 to fix the UNS Electric term loan variable interest rate. The company accounts for this hedge using the same policies that TEP applies to its cash flow hedges. See Note 4.

UniSource Energy and TEP had liabilities related to their cash flow hedges of $14 million at September 30, 2011, and $12 million at December 31, 2010.

The after-tax unrealized losses on derivative activities reported in AOCI were as follows:


	UniSource Energy				TEP
	Three Months Ended September 30,
	2011		2010		2011		2010
	-Millions of Dollars-
After-Tax Unrealized Losses	$	2	$	3	$	2	$	3


	Nine Months Ended September 30,
	2011		2010		2011		2010
	-Millions of Dollars-
After-Tax Unrealized Losses	$	3	$	8	$	3	$	8

Regulatory Treatment of Commodity Derivatives

We disclose unrealized gains and losses on energy contracts recoverable through the PPFAC or PGA on the balance sheet as a regulatory asset or liability rather than as a component of AOCI or in the income statement, as shown in the following table:


	UniSource Energy				TEP
	Three Months Ended September 30,
	2011		2010		2011			2010
	-Millions of Dollars-
Increase (Decrease) to Regulatory Assets	$	2	$	6	$	(1	)	$	(1	)


	Nine Months Ended September 30,
	2011			2010		2011			2010
	-Millions of Dollars-
Increase (Decrease) to Regulatory Assets	$	(7	)	$	10	$	(3	)	$	(4	)

The fair value of assets and liabilities for energy derivatives recoverable through the PPFAC or PGA were as follows:


	UniSource Energy						TEP
	September 30,			December 31,			September 30,			December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Assets	$	14		$	15		$	3		$	3
Liabilities		(33	)		(42	)		(4	)		(7	)

Net Liabilities	$	(19	)	$	(27	)	$	(1	)	$	(4	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) — Unaudited

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


	UniSource Energy				TEP
	Three Months Ended September 30,
	2011		2010		2011		2010
	-Millions of Dollars-
Realized Losses on Settled Gas Swaps	$	6	$	8	$	4	$	5


	Nine Months Ended September 30,
	2011		2010		2011		2010
	-Millions of Dollars-
Realized Losses on Settled Gas Swaps	$	15	$	17	$	6	$	8

At September 30, 2011, UniSource Energy and TEP had contracts that will settle through the third quarter of 2015.

Other Commodity Derivatives

UniSource Energy and TEP record realized and unrealized gains and losses on other energy contracts on a net basis in Wholesale Sales. The settlement of forward power purchase and sales contracts that did not result in physical delivery were as follows:


	UniSource Energy and TEP
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	-Millions of Dollars-
Recorded in Wholesale Sales:
Forward Power Sales	$	6		$	19		$	9		$	25
Forward Power Purchases		(8	)		(25	)		(12	)		(32	)

Total Purchases Not Resulting in Physical Delivery	$	(2	)	$	(6	)	$	(3	)	$	(7	)

DERIVATIVE VOLUMES

At September 30, 2011, UniSource Energy had gas swaps totaling 13,963 GBtu and power contracts totaling 3,647 GWh while TEP had gas swaps totaling 5,977 GBtu and power contracts totaling 964 GWh, At December 31, 2010, UniSource Energy had gas swaps totaling 14,973 GBtu and power contracts totaling 4,807 GWh while TEP had gas swaps totaling 6,424 GBtu and power contracts totaling 1,144 GWh. We account for gas swaps and power contracts as derivatives.

CREDIT RISK ADJUSTMENT

The impact of counterparty credit risk and the impact of our own credit risk on the fair value of derivative asset contracts was less than $0.1 million at September 30, 2011, and at December 31, 2010.

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 September 30, 2011. It also shows cash collateral and letters of credit posted, and additional collateral to be posted if credit-risk related contingent features were triggered.


	UniSource Energy		TEP
	September 30, 2011
	-Millions of Dollars-
Net Liability	$	58	$	21
Cash Collateral Posted		—		—
Letters of Credit		8		1
Additional Collateral to Post if Contingent Features Triggered		52		21

As of September 30, 2011, TEP had $17 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities; five of these counterparties individually comprised greater than 10% of the total credit exposure. At September 30, 2011, UNS Electric had $3 million of credit exposure related to its supply and hedging contracts; this amount was concentrated primarily with one counterparty. At September 30, 2011, UNS Gas had immaterial exposure to other counterparties’ creditworthiness.

NOTE 15. REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

UniSource Energy’s and TEP’s condensed consolidated financial statements as of September 30, 2011 and for the three and nine months ended September 30, 2010 and 2011, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their reports (dated October 31, 2011) 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 (the Act) for their reports on the unaudited financial information because neither of those reports is a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

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 UniSource Energy and its three primary business segments. It includes the following:

•

outlook and strategies;

•

operating results during the third quarter and nine-months ended September 30, 2011, compared with the same periods in 2010;

•

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) UniSource Energy’s and TEP’s 2010 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 nine months ended September 30, 2011 and 2010. Management’s Discussion and Analysis explains the differences between periods for specific line items of the Condensed Consolidated Financial Statements.

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

UNISOURCE ENERGY CONSOLIDATED

OVERVIEW OF CONSOLIDATED BUSINESS

UniSource Energy is a holding company with no significant operations of its own. UniSource Energy’s operating subsidiaries are separate legal entities with their own assets and liabilities. UniSource Energy owns the outstanding common stock of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), UniSource Energy Development Company (UED), and Millennium Energy Holdings, Inc. (Millennium).

Our business includes three primary business segments: TEP; UNS Gas, Inc. (UNS Gas); and UNS Electric, Inc. (UNS Electric). TEP is an electric utility serving the community of Tucson, Arizona. UES provides gas and electric service to more than 30 communities in northern and southern Arizona through its two operating subsidiaries, UNS Gas and UNS Electric.

Other subsidiaries include UED, which developed the Black Mountain Generating Station (BMGS) in northwestern Arizona in 2008. The facility, which includes two natural gas-fired combustion turbines, provided energy to UNS Electric through a power sales agreement. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction did not impact UniSource Energy’s consolidated financial statements.

Millennium, another subsidiary, has existing investments in unregulated businesses that represented less than 1% of UniSource Energy’s total assets as of September 30, 2011. We have no new investments planned for Millennium. Southwest Energy Solutions (SES) is a subsidiary of Millennium that provides supplemental labor and meter reading services to TEP, UNS Gas, and UNS Electric.

UniSource Energy was incorporated in the state of Arizona in 1995 and obtained regulatory approval to form a holding company in 1997. TEP and UniSource Energy exchanged shares of stock in 1998, making TEP a subsidiary of UniSource Energy.

OUTLOOK AND STRATEGIES

Our financial prospects and outlook are affected by many factors including: the TEP 2008 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:

•

Focusing 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.

•

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

•

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

•

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

RESULTS OF OPERATIONS

Contribution by Business Segment

The table below shows the contributions to our consolidated after-tax earnings by our three business segments as well as Other Non-Reportable Segments.


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	-Millions of Dollars-						-Millions of Dollars-
TEP	$	54		$	60		$	84		$	98
UNS Gas		(1	)		(1	)		6			5
UNS Electric		7			5			14			12
Other Non-Reportable Segments and Adj.⁽¹⁾		—			(8	)		(2	)		(13	)

Consolidated Net Income	$	60		$	56		$	102		$	102


⁽¹⁾		Includes: UniSource Energy parent company expenses; Millennium; and UED.

Revision of Prior Period Financial Statements

Executive Overview

Third Quarter of 2011 Compared with the Third Quarter of 2010

TEP

TEP reported net income of $54 million in the third quarter of 2011 compared with $60 million in the third quarter of 2010. Net income in the third quarter of 2011 includes the recognition of a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric. This item was offset by lower retail and long-term wholesale margin revenues, as well as increases in depreciation expense and interest expense. SeeTucson Electric Power Company, Results of Operations,below for more information.

UNS Gas and UNS Electric

UNS Electric reported net income of $7 million in the third quarter of 2011 compared with net income of $5 million in the third quarter of 2010. The increase is due in part to a base rate increase that took effect in October 2010. SeeUNS Electric, Results of Operations,below for more information.

UNS Gas reported a net loss of $1 million in both the third quarters of 2011 and 2010. SeeUNS Gas, Results of Operations,below for more information.

Other Non-Reportable Segments

Millennium’s financial results are included in UniSource Energy’s Other Non-Reportable Segments. Millennium reported net income of $1 million in the third quarter of 2011 compared with a net loss of $6 million in the same period last year. Millennium’s results in the third quarter of 2010 reflect losses related to the write-off of deferred taxes and impairment losses.

SeeOther Non-Reportable Segments, Results of Operations,below, for more information.

Nine Months Ended September 30, 2011 Compared with the Nine Months Ended September 30, 2010

TEP reported net income of $84 million in the first nine months of 2011 compared with $98 million in the same period in 2010. The decrease in net income is due primarily to: a decline in long-term wholesale margin revenues; a decrease in wholesale transmission revenues; an increase in Base O&M; higher depreciation expense; and an increase in interest expense. Those factors were partially offset by the recognition of a gain related to the settlement of a dispute with El Paso Electric. SeeTucson Electric Power, Results of Operationsbelow for more information.

UNS Gas and UNS Electric

UNS Gas reported net income of $6 million in the first nine months of 2011 compared with net income of $5 million in the same period last year. SeeUNS Gas, Results of Operations,below for more information.

UNS Electric reported net income of $14 million in the first nine months of 2011 compared with net income of $12 million in the same period last year. The increase is due in part to a base rate increase that took effect in October 2010. SeeUNS Electric, Results of Operations,below for more information.

Other Non-Reportable Segments

Millennium’s financial results are included in UniSource Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in the first nine months of 2011 compared with a net loss of $9 million in the same period last year. Millennium’s results in the third quarter of 2010 reflect losses related to the write-off of deferred taxes and impairment losses.

SeeOther Non-Reportable Segments, Results of Operations,below, for more information.

Operations and Maintenance Expense

The table below summarizes the items included in UniSource Energy’s O&M expense:


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	-Millions of Dollars-
TEP Base O&M (non-GAAP)⁽¹⁾	$	54		$	53		$	173		$	162
UNS Gas Base O&M (non-GAAP)⁽¹⁾		5			6			18			18
UNS Electric Base O&M (non-GAAP)⁽¹⁾		5			5			15			16
Consolidating Adjustments and Other⁽²⁾		(2	)		(2	)		(8	)		(7	)

UniSource Energy Base O&M (non-GAAP)		62			62			198			189
Reimbursed Expenses Related to Springerville Units 3 and 4		16			14			49			41
Expenses related to customer-funded renewable energy and demand side management programs		13			13			35			29

Total UniSource Energy O&M (GAAP)	$	91		$	89		$	282		$	259


⁽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 GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core utility business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.

⁽²⁾		Includes Millennium, UED, and UniSource Energy stand-alone O&M, and inter-company eliminations.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Dividends from UniSource Energy’s subsidiaries, primarily TEP, represent the parent company’s main source of liquidity. Under UniSource Energy’s tax sharing agreement, subsidiaries make income tax payments to UniSource Energy, which makes payments on behalf of the consolidated group. The table below provides a summary of the liquidity position of UniSource Energy and each of its segments.


				Borrowings under		Amount Available
	Cash and Cash			Revolving Credit		under Revolving
Balances as of October 20, 2011	Equivalents			Facility⁽¹⁾		Credit Facility
	-Millions of Dollars-
UniSource Energy Stand-Alone	$	3		$	71	$	54
TEP	23				1		199
UNS Gas	33				—		70	⁽²⁾
UNS Electric		7			8		62	⁽²⁾
Other	6		⁽³⁾		N/A		N/A

Total	$	72


⁽¹⁾		Includes 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.

Short-term Investments

UniSource 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 September 30, 2011, UniSource Energy’s short-term investments included highly-rated and liquid money market funds, certificates of deposit, and commercial paper. These short-term investments are classified as Cash and Cash Equivalents on the Balance Sheet.

Access to Revolving Credit Facilities

UniSource Energy and its three primary subsidiaries have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2014. The TEP and UNS Gas/UNS Electric Credit Agreements may be used for revolving borrowings as well as to issue letters of credit. TEP, UNS Gas, and UNS Electric each issue letters of credit from time to time to provide credit enhancement to counterparties for their power or gas procurement and hedging activities. The UniSource 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. SeeItem 3.Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Liquidity Outlook

The UED Credit Agreement was repaid in July 2011 upon UNS Electric’s acquisition of BMGS. SeeOther Non-Reportable Business Segments, UEDbelow.

Executive Overview — UniSource Energy Consolidated Cash Flows


Nine Months Ended September 30,	2011			2010
	-Millions of Dollars-
Operating Activities	$	260		$	256
Investing Activities		(216	)		(233	)
Financing Activities		(52	)		(32	)

UniSource Energy’s operating cash flows are generated primarily by the 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. UniSource Energy, TEP, UNS Gas and UNS Electric 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 UniSource Energy to its shareholders.

Operating Activities

In the first nine months of 2011, net cash flows from operating activities were $4 million higher than they were in the same period last year due to:

	•		a $38 million increase in cash receipts from electric and gas sales, net of fuel and purchased energy costs. The increase was due in part to: a base rate increase at UNS Gas in April 2010; a base rate increase at UNS Electric in October 2010; an increase in retail electric sales; higher fuel and purchased power cost recoveries from UNS Electric customers; and higher sales tax collections from customers resulting from a 1% increase in the sales tax rate that took effect in June 2010; and

	•		a $14 million decrease in income taxes paid net of income tax refunds; partially offset by

	•		a $43 million increase in O&M costs due in part to higher scheduled generating plant outage costs, an increase in up-front incentive payments for customer-installed solar systems, higher DSM payments, and timing differences in contributions to TEP’s pension plan; and

	•		a $16 million increase in taxes other than income taxes paid.

Investing Activities

Net cash flows used for investing activities decreased by $17 million in the first nine months of 2011. Investing activities in the first nine months of 2011 included a $13 million increase in proceeds from investments in Springerville lease debt and $3 million in proceeds from the sale of land and buildings. Capital expenditures during the first nine months of 2011 were $263 million compared with $259 million the same period last year (including the purchase of Sundt Unit 4 for $51 million in the first nine months of 2010).

Capital Expenditures


	Actual Year-to-Date
	September 30, 2011
	-Millions of Dollars-
TEP	$	194
UNS Gas		10
UNS Electric⁽¹⁾		25
Other Capital Expenditures⁽²⁾		34

UniSource Energy Consolidated	$	263


(1)		UNS Electric purchased BMGS from UED for approximately $63 million in July 2011. Since this is an inter-company transaction, it is not included in the chart above, as it is eliminated from UniSource Energy consolidated capital expenditures. SeeUNS Electric, Liquidity and Capital Resources, Cash Flows and Capital Expenditures, below for more information.

(2)		Primarily capital expenditures by UniSource Energy for the construction of a new headquarters building in Tucson, Arizona.

Total UniSource Energy consolidated capital expenditures for 2011 are expected to be $394 million.

Financing Activities

Net cash flows used for financing activities were $20 million higher in the first nine months of 2011 compared with the same period last year primarily due to:

•

an $18 million increase in payments on capital lease obligations;

•

a $7 million decrease in proceeds from the issuance of long-term debt (net of long-term debt repayments and issuance/retirement costs);

•

a $4 million increase in common stock dividends paid; and

•

a $5 million decrease in cash from other financing activities.

offset by

•

a $17 million increase in borrowings (net of repayments) under revolving credit facilities.

Capital Contributions

In July 2011, UniSource Energy contributed $20 million in capital to UNS Electric to help fund its purchase of BMGS from UED.

In July 2011, UED used the proceeds from the sale of BMGS to retire outstanding loans under the UED Credit Agreement and to pay a dividend of $36 million to UniSource Energy.

In the first nine months of 2010, UED paid UniSource Energy a $9 million dividend, of which $4 million represented a return of capital distribution. UniSource Energy contributed $15 million in capital to TEP in the first nine months of 2010 to help fund the purchase of Sundt Unit 4.

UniSource Credit Agreement

The UniSource Credit Agreement consists of a $125 million revolving credit and revolving letter of credit facility. The UniSource Credit Agreement expires in November 2014. As of September 30, 2011, there was $71 million outstanding at a weighted-average interest rate of 3.23%.

The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UniSource Credit Agreement also requires UniSource Energy to meet a minimum cash flow to interest coverage ratio. This ratio is determined on a UniSource Energy stand-alone basis. Additionally, UniSource Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UniSource Credit Agreement, UniSource Energy may pay dividends as long as it maintains compliance with the agreement.

As of September 30, 2011, we were in compliance with the terms of the UniSource Credit Agreement.

Interest Rate Risk

UniSource 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. UniSource Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if LIBOR and other benchmark interest rates increase. SeeItem 3. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Convertible Senior Notes

UniSource Energy has $150 million of 4.50% Convertible Senior Notes due 2035. Each $1,000 of Convertible Senior Notes can be converted into 28.633 shares of UniSource Energy Common Stock at any time. The conversion ratio represents a conversion price of approximately $34.92 per share of our Common Stock, subject to adjustments including an adjustment to reduce the conversion price upon the payment of quarterly dividends in excess of $0.19 per share. The closing price of UniSource Energy’s Common Stock was $37.38 on October 20, 2011.

UniSource Energy has the option to redeem the notes, in whole or in part, for cash, at a price equal to 100% of the principal amount plus accrued and unpaid interest. Holders of the notes will have the right to require UniSource Energy to repurchase the notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain specified fundamental changes involving UniSource Energy occur. The repurchase price will be 100% of the principal amount of the notes plus accrued and unpaid interest.

Contractual Obligations

There are no significant changes in our contractual obligations or other commercial commitments from those reported in our 2010 Annual Report on Form 10-K, other than the following obligations established in 2011:


Payment Due in Years											2016
Ending December 31,	2011		2012		2013		2014		2015		and after		Total
	-Millions of Dollars-
Long Term Debt¹	$	—	$	—	$	—	$	—	$	30	$	50	$	80
Purchase Obligations:
Fuel		34		43		17		16		—		—		110
Transportation²		3		4		4		4		4		8		27
Purchased Power³		4		43		44		56		15		242		404
Solar Equipment		12		12		12		—		—		—		36
Building Improvements		10		—		—		—		—		—		10

Total Additional Contractual Cash Obligations	$	63	$	102	$	77	$	76	$	49	$	300	$	667


⁽¹⁾		UNS Electric entered into a 4-year $30 million variable rate term loan credit agreement following acquisition of BMGS from UED. UED used a portion of the proceeds from the sale of BMGS to repay the $27 million outstanding under its secured term loan. In August 2011, UNS Gas issued $50 million of senior guaranteed notes, due August 2026, and used the proceeds to repay in full the $50 million of UNS Gas notes that matured in August 2011.

⁽²⁾		TEP executed a new transportation agreement requiring minimum annual transport quantities of 2.4 million tons of coal to its Springerville Generating Station from July 1, 2011 through December 2017.

⁽³⁾		Purchased Power includes three long-term Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011. TEP is obligated to purchase 100% of the output from two of these facilities and UNS Electric is obligated to purchase 100% of the output from the third facility. The table above includes estimated future payments based on expected power deliveries through 2031. TEP and UNS Electric have entered into additional long-term renewable PPAs to comply with the RES requirements; however, TEP’s and UNS Electric’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

Dividends on Common Stock

The following table shows the dividends declared to UniSource Energy shareholders for 2011:


			Dividend Amount Per
Declaration Date	Record Date	Payment Date	Share of Common Stock
February 25, 2011	March 11, 2011	March 23, 2011	$	0.42
May 6, 2011	May 19, 2011	June 6, 2011	$	0.42
August 5, 2011	August 18, 2011	September 1, 2011	$	0.42

Income Tax Position

As of September 30, 2011, UniSource Energy and TEP had the following carry-forward amounts:


	UniSource Energy				TEP
	Amount		Expiring Year		Amount		Expiring Year
	-Amounts in Millions of Dollars-
Capital Loss	$	8		2015	$	—		—
Federal NOL		99		2031		85		2031
AMT Credit		37	None			19	None

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 UniSource Energy otherwise would have received over 20 years. As a result of these provisions, UniSource Energy does not expect to pay any federal income taxes for the tax years 2011 and/or 2012.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

Executive Summary

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

Third Quarter of 2011 Compared with Third Quarter of 2010

TEP reported net income of $54 million in the third quarter of 2011 compared with net income of $60 million in the third quarter of 2010. The following factors impacted TEP’s results in the third quarter of 2011:

•

a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric;

offset by

•

a $3 million decrease in retail margin revenues due to a 1.3% decrease in retail kWh sales;

•

a $5 million decline in long-term wholesale margin revenues resulting from a change in the pricing of energy sold under the Salt River Project (SRP) wholesale contract effective June 1, 2011;

•

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

•

a $2 million increase in interest expense due in part to an increase in the amount of long-term debt outstanding and higher fees associated with the TEP Credit Agreement that was refinanced in November 2010; and

•

a $2 million decrease in total other income.

Nine Months Ended September 30, 2011 Compared with the Nine Months Ended September 30, 2010

TEP recorded net income of $84 million in the first nine months of 2011 compared with $98 million in the same period last year. The following factors contributed to the decrease in TEP’s net income:

•

an $8 million decline in long-term wholesale margin revenues resulting primarily from a change in the pricing of energy sold under the SRP wholesale contract effective June 1, 2011;

•

a $4 million decrease in wholesale transmission revenues. In the first quarter of 2010, transmission revenues benefitted from the temporary sale of transmission capacity to SRP;

•

an $11 million increase in Base O&M primarily due to TEP’s share of planned generating plant maintenance expense at San Juan, which is operated by PNM;

•

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

•

a $2 million decrease in other income;

partially offset by

•

a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric; and

•

a $3 million loss related to the settlement of disputed wholesale power transactions recorded in the first quarter of 2010.

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 third quarters of 2011 and 2010.


					Increase (Decrease)
Three Months Ended September 30,	2011		2010		Amount			Percent*
Energy Sales, kWh (in millions)
Electric Retail Sales:
Residential		1,417		1,445		(28	)		(1.9	%)
Commercial		598		612		(14	)		(2.3	%)
Industrial		632		630		2			0.4	%
Mining		274		274		—			(0.1	%)
Public Authorities		65		65		—			0.2	%

Total Electric Retail Sales		2,986		3,026		(40	)		(1.3	%)


Retail Margin Revenues (in millions):
Residential	$	95	$	97	$	(2	)		(2.6	%)
Commercial		50		51		(1	)		(2.2	%)
Industrial		29		29		—			(0.3	%)
Mining		8		8		—			2.5	%
Public Authorities		3		3		—			0.0	%

Total Retail Margin Revenues (Non-GAAP)**	$	185	$	188	$	(3	)		(1.9	%)
PPFAC Revenues		112		100		12			11.9	%
RES & DSM Revenues		12		12		—			1.7	%

Total Retail Revenues (GAAP)	$	309	$	300	$	9			2.9	%


Avg. Retail Margin Rate (cents / kWh):
Residential		6.66		6.70		(0.04	)		(0.6	%)
Commercial		8.36		8.35		0.01			0.1	%
Industrial		4.54		4.57		(0.03	)		(0.7	%)
Mining		3.03		2.95		0.08			2.7	%
Public Authorities		5.20		5.21		(0.01	)		(0.2	%)

Avg. Retail Margin Rate		6.19		6.22		(0.03	)		(0.5	%)
Avg. PPFAC Rate		3.76		3.31		0.45			13.6	%
Avg. RES & DSM Rate		0.40		0.39		0.01			2.6	%

Total Avg. Retail Rate		10.35		9.92		0.43			4.3	%


Weather Data:	2011		2010
Cooling Degree Days
Three Months Ended September 30		1,090		1,096		(6	)		(0.5	%)
10-Year Average		990		978		12			1.2	%


*		Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

**		Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net Electric Retail Sales, which is determined in accordance with GAAP. Retail Margin Revenues excludes: (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 operating expenses of our core utility business.

Residential

Residential kWh sales were 1.9% lower in the third quarter of 2011 than they were during the same period last year, leading to a decrease in residential margin revenues of 2.6%, or $2 million. Residential use per customer decreased by 2.2% compared with the third quarter of 2010. Cooling Degree Days during the third quarter of 2011 were 0.5% lower than the same period last year. The average number of residential customers grew by 0.3% in the third quarter of 2011 compared with the same period last year.

Commercial

Commercial kWh sales fell by 2.3% compared with the third quarter of 2010, leading to a decline in margin revenues by 2.2%, or $1 million. Commercial use per customer decreased by 3.0% compared with the third quarter of 2010. The average number of commercial customers grew by 0.7% in the third quarter of 2011 compared with the same period last year.

Industrial

Industrial kWh sales increased by 0.4% compared with the third quarter of 2010; however, margin revenues declined by 0.3%. The decline in margin revenues is due to changing usage patterns by certain industrial customers that reduced their demand charges paid to TEP.

Mining

Mining kWh sales decreased by 0.1% in the third quarter of 2011 compared with the same period last year. Despite lower sales volumes, margin revenues from mining customers increased by 3.0%. High copper prices have prompted mines to alter their energy usage patterns, leading to higher demand charges paid to TEP.

Long-Term Wholesale and Transmission Revenues


					Increase (Decrease)
Three Months Ended September 30,	2011		2010		Amount			Percent*
Long-Term Wholesale Contracts
kWh Sales (millions)		231		224		7			3.1	%
Total Revenues ($ millions)	$	9	$	14	$	(5	)		(35.5	%)
Margin Revenues ($ millions)	$	1	$	6	$	(5	)		(89.3	%)
Wholesale Transmission Revenues($ millions)	$	4	$	4	$	—			(8.8	%)


*		Percent change calculated on unrounded data and may not exactly correspond to data shown in table.

Margin revenues from long-term wholesale contracts fell $5 million compared to the third quarter of 2010. The reduction resulted from a change in pricing under the SRP contract. SeeFactors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project, below, for more information.

Short-Term Wholesale Revenues

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

The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the first nine months of 2011 and 2010.

Utility Sales and Revenues


					Increase (Decrease)
Nine Months Ended September 30,	2011		2010		Amount			Percent*
Energy Sales, kWh (in millions)
Electric Retail Sales:
Residential		3,108		3,109		(1	)		—
Commercial		1,517		1,516		1			0.1	%
Industrial		1,654		1,639		15			0.9	%
Mining		811		807		4			0.5	%
Public Authorities		182		178		4			2.3	%

Total Electric Retail Sales		7,272		7,249		23			0.3	%


Retail Margin Revenues (in millions):
Residential	$	203	$	203	$	—			(0.4	%)
Commercial		124		124		—			0.1	%
Industrial		73		74		(1	)		(1.2	%)
Mining		24		23		1			2.9	%
Public Authorities		9		9		—			2.2	%

Total Retail Margin Revenues (Non-GAAP)**	$	433	$	433	$	—			(0.2	%)
PPFAC Revenues		245		222		23			10.5	%
RES & DSM Revenues		36		30		6			21.1	%

Total Retail Revenues (GAAP)	$	714	$	685	$	29			4.2	%


Avg. Retail Margin Rate (cents / kWh):
Residential		6.52		6.54		(0.02	)		(0.3	%)
Commercial		8.14		8.14		—			0.0	%
Industrial		4.43		4.52		(0.09	)		(2.0	%)
Mining		2.94		2.88		0.06			2.1	%
Public Authorities		5.10		5.11		(0.01	)		(0.2	%)

Avg. Retail Margin Rate		5.95		5.98		(0.03	)		(0.5	%)
Avg. PPFAC Rate		3.38		3.07		0.31			10.1	%
Avg. RES & DSM Rate		0.50		0.41		0.09			22.0	%

Total Avg. Retail Rate		9.83		9.46		0.37			3.9	%


Weather Data:
Cooling Degree Days
Nine Months Ended Sept. 30		1,480		1,491		(11	)		(0.7	%)
10-Year Average		1,434		1,433		1			0.1	%
Heating Degree Days
Nine Months Ended Sept. 30		903		970		(67	)		(6.9	%)
10-Year Average		851		871		(20	)		(2.3	%)


*		Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

**		Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net Electric Retail Sales, which is determined in accordance with GAAP. Retail Margin Revenues excludes: (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 operating expenses of our core utility business.

Residential

In the first nine months of 2011, residential kWh sales and retail margin revenues did not materially change.

Commercial

Commercial kWh sales and margin revenues did not materially change in the first nine months of 2011 compared with the same period last year.

Industrial

Industrial kWh sales increased by 0.9% compared with the first nine months of 2010, while margin revenues declined by 1.2%. The decline in margin revenues, despite higher kWh sales, is due to changing 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 0.5% increase in sales volumes in the first nine months of 2011 compared with the same period last year. Margin revenues from mining customers increased by 3.0% over the same period last year due to higher energy consumption and changing usage patterns that increased their demand charges paid to TEP.

Long-Term Wholesale and Transmission Revenues


					Increase (Decrease)
Nine Months Ended September 30,	2011		2010		Amount			Percent
Long-Term Wholesale Contracts
kWh Sales (millions)		735		727		8			1.1	%
Total Revenues ($ millions)	$	33	$	42	$	(9	)		(21.3	%)
Margin Revenues ($ millions)	$	12	$	20	$	(8	)		(42.5	%)

Wholesale Transmission Revenues($ millions)	$	12	$	16	$	(4	)		(21.0	%)

Margin revenues from long-term wholesale contracts were $8 million lower than in the first nine months of 2010. The decrease was due primarily to a change in pricing under the SRP contract. SeeFactors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project,below, for more information.

Short-Term Wholesale Revenues

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

Other Revenues


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	-Millions of Dollars-				-Millions of Dollars-
Revenue related to Springerville Units 3 and 4⁽¹⁾	$	24	$	22	$	74	$	65
Other Revenue		7		6		20		16

Total Other Revenue	$	31	$	28	$	94	$	81


⁽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.

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, including those stemming from 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 nine months ended September 30, 2011 and 2010 are detailed below.


	Generation and						Fuel and Purchased
	Purchased Power						Power Expense
TEP	2011			2010			2011			2010
Three Months Ended September 30,	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation		2,807			2,639		$	73		$	59
Gas-Fired Generation		331			383			21			24
Renewable Generation		7			6			—			—

Total Generation		3,145			3,028			94			83
Total Purchased Power		898			1,028			41			48
Reimbursed Fuel Expense		—			—			2			2
Transmission		—			—			(4	)		1
Increase (Decrease) to Reflect PPFAC Recovery Treatment		—			—			1			(13	)

Total Resources		4,043			4,056		$	133		$	121

Less Line Losses and Company Use		(273	)		(304	)

Total Energy Sold		3,770			3,752


	Generation and						Fuel and Purchased
	Purchased Power						Power Expense
TEP	2011			2010			2011			2010
Nine Months Ended September 30,	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation		7,680			6,950		$	195		$	159
Gas-Fired Generation		707			768			45			46
Renewal Generation		18			19			—			—

Total Generation		8,405			7,737			240			205
Total Purchased Power		2,047			2,393			84			106
Reimbursed Fuel Expense		—			—			6			5
Transmission		—			—			(2	)		3
Increase (Decrease) to Reflect PPFAC Recovery Treatment		—			—			(5	)		(23	)

Total Resources		10,452			10,080		$	323		$	296

Less Line Losses and Company Use		(657	)		(629	)

Total Energy Sold		9,795			9,451

Generation

Total generating output increased during the third quarter and first nine months of 2011 compared with the same periods last year. The higher output was primarily due to the increased availability of TEP’s largest coal-fired generating plants, Springerville Units 1 and 2. Both units experienced unplanned outages during the first nine months of 2010, and Unit 2 also underwent a planned maintenance outage during the first quarter of 2010.

Purchased Power

Purchased power volumes decreased in both the third quarter and first nine months of 2011 compared with the same periods last year. The lower volume of power purchases was primarily due to the increased availability of TEP’s coal-fired generating resources.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	-cents per kWh-				-cents per kWh-
Coal		2.62		2.23		2.53		2.28
Gas		6.26		6.39		6.42		6.00
Purchased Power		4.51		4.66		4.11		4.43

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 was the same in the third quarters of 2011 and 2010, and 14% lower in the first nine months of 2011 than in the same period last year. The average price for natural gas based on the Permian Index in the third quarter and first nine months of 2011 was higher by 4% and lower by 7%, respectively, compared with the same periods in 2010. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during the remainder of 2011.


Average Market Price for Around-the-Clock Energy	$/MWh
Quarter ended September 30, 2011	$	35
Quarter ended September 30, 2010		35

Nine months ended September 30, 2011	$	30
Nine months ended September 30, 2010		35


Average Market Price for Natural Gas	$/MNBtu
Quarter ended September 30, 2011	$	4.09
Quarter ended September 30, 2010		3.94

Nine months ended September 30, 2011	$	4.04
Nine months ended September 30, 2010		4.33

O&M

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	-Millions of Dollars-						-Millions of Dollars-
Base O&M (Non-GAAP)⁽¹⁾	$	54		$	53		$	173		$	162
O&M recorded in Other Expense		(1	)		(2	)		(5	)		(5	)
Reimbursed expenses related to Springerville Units 3 and 4		16			14			48			41
Expenses related to customer funded renewable energy and DSM programs		11			10			30			22

Total O&M (GAAP)	$	80		$	75		$	246		$	220


⁽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 GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core utility business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.

FACTORS AFFECTING RESULTS OF OPERATIONS

Base Rate Increase Moratorium

Pursuant to the 2008 TEP Rate Order, TEP’s base rates are frozen through at least December 31, 2012. TEP is prohibited from submitting an application for new base rates before June 30, 2012. The test year to be used in TEP’s next base rate application cannot end earlier than December 31, 2011.

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.

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 Units 3 and 4 on behalf of Tri-State and SRP, respectively. The table below summarizes the pre-tax income related to the operation of Springerville Units 3 and 4 as well as the income statement line items where TEP records revenues and expenses related to those units.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	-Millions of Dollars-						-Millions of Dollars-
Other Revenues	$	24		$	22		$	74		$	65
Fuel Expense		(2	)		(2	)		(6	)		(5	)
Operations and Maintenance Expense		(16	)		(14	)		(49	)		(41	)
Taxes Other Than Income Taxes		—			—			(1	)		(1	)

Total Pre-Tax Income	$	6		$	6		$	18		$	18

Refinancing Activity

In November 2010, TEP amended and restated its existing credit agreement. As a result of the increased interest rate on borrowings under the TEP Revolving Credit Facility and the margin rate in effect on the TEP Letter of Credit Facility, TEP’s interest expense, excluding interest expense related to capital lease obligations, was $36 million in the first nine months of 2011 compared with $30 million in the same period of last year.

Pension and Postretirement Benefit Expense

In the third quarter of 2011, TEP charged $4 million of pension and postretirement benefit expenses to O&M expense, compared with $4 million in the third quarter of 2010. TEP charged $12 million of pension and postretirement benefit expenses to O&M expense in the first nine months of 2011, compared with $11 million in the same period last year. In 2011, TEP expects to charge approximately $15 million of pension and postretirement benefit expense to O&M expense, compared with $13 million in 2010.

Long-Term Wholesale Sales

TEP’s two primary long-term wholesale contracts are with SRP and NTUA. TEP’s margin on long-term wholesale sales was $12 million during the first nine months of 2011, compared with $20 million in the same period last year.

TEP estimates its margin on long-term wholesale sales in 2011 will be $14 million, compared with $28 million in 2010. The decrease is a result of changes in the terms of the SRP contract described below.

Salt River Project

Under terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, or $22 million annually, through May 31, 2011. The contract states that as of June 1, 2011, TEP is no longer to receive the monthly demand charge, and SRP is required to purchase 73,000 MWh per month, or 876,000 MWh annually, based on an energy price at a slight discount to the Palo Verde Market Index. As of October 20, 2011, the average around-the-clock forward price of power on the Palo Verde Market Index for the balance of 2011 was approximately $28 per MWh and approximately $31 per MWh for the calendar year 2012.

Navajo Tribal Utility Authority

TEP serves the portion of NTUA’s load that is not served by the authority’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh per year. Since 2010, the price of 50% of the MWh sales to NTUA from June to September has been based on the Palo Verde Market Index. In 2010, approximately 14% of the total energy sold to NTUA was priced based on the Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA.

Settlement of El Paso Electric Dispute

TEP recognized a pre-tax gain of approximately $7 million, including interest, in the third quarter of 2011 when the FERC approved the settlement agreement between TEP and El Paso.

In April 2011, TEP and El Paso entered into a settlement agreement, subject to approval by the FERC, to resolve a dispute over transmission service from Luna to TEP’s system that originated in 2006 under the 1982 Power Exchange and Transmission Agreement between the parties (Exchange Agreement). In 2008, the FERC issued an order supporting TEP’s position in the dispute; El Paso subsequently appealed that order. In December 2008, El Paso refunded $11 million, including interest, to TEP for transmission service from Luna to TEP’s system from 2006 to 2008.

The settlement agreement allows TEP to use rights for transmission that exist under the Exchange Agreement for transmission of power from both Luna and a new interconnection at Macho Springs to TEP’s system. In accordance with the settlement agreement TEP has entered into two new firm transmission service agreements under El Paso’s Open Access Transmission Tariff for a total of 40 MW. The settlement agreement also requires El Paso to withdraw its appeal before the United States Court of Appeals District of Columbia Circuit and requires TEP to withdraw its related complaint before the Arizona District of the United States District Court. FERC approved the settlement agreement in August 2011. By its terms, the settlement agreement is effective November 1, 2011. See Note 6 for more information.

Energy Efficiency Standards (EE Standards)

In August 2010, the ACC approved new EE Standards designed to require TEP, UNS Electric and other affected electric utilities to implement cost-effective programs to reduce customers’ energy consumption. In 2010, TEP’s programs saved energy equal to 1.1% of its 2009 sales. In 2011, the EE Standards target total kWh savings of 1.25% of 2010 sales. The EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.

The EE Standards can be met by new and existing DSM programs, direct load control programs and energy efficient building codes. The EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s programs and rates charged to customers for such programs are subject to annual approval by the ACC.

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 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 expects to file its next general rate case on or after June 30, 2012.

In January 2011, TEP filed its 2011-2012 Energy Efficiency Implementation Plan with the ACC. The plan includes a request to approve an interim mechanism that would allow the recovery of lost revenues resulting from the implementation of energy efficiency measures. TEP’s request, which was updated in August 2011, seeks recovery of up to $4 million in 2011 and up to $13 million in 2012. The ACC is expected to consider TEP’s request during the fourth quarter of 2011.

Competition

New technological developments and the success of energy efficiency programs 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 for the sale of electric capacity and energy.

Renewable Energy Standard and Tariff

In 2010, the ACC approved a funding mechanism that allows TEP to recover operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through RES funds until such costs are reflected in TEP’s base rates. TEP invested $14 million in two solar projects that were completed in December 2010 and began cost recovery through the RES surcharge in January 2011. During 2011, TEP expects to earn approximately $1 million pre-tax on its 2010 investment in solar projects. The ACC approved an additional investment of $28 million for approximately 7 MW of solar capacity to be built during 2011. In accordance with the funding mechanism approved by the ACC in 2010, TEP could earn approximately $4 million pre-tax in 2012 on solar investments made in 2010 and 2011.

TEP filed its 2012 RES implementation plan with the ACC in July 2011. In that filing, TEP is seeking ACC approval for annual investments of $28 million in both 2012 and 2013 to fund development of approximately 14 MW of company-owned solar capacity. In October 2011, ACC staff filed a recommendation that, if approved, could impact the current funding mechanism for company-owned solar projects as well as TEP’s strategy for meeting the RES. TEP expects the ACC to consider TEP’s 2012 RES implementation plan in the fourth quarter of 2011.

Line Extension Policy

In June 2011, the ACC determined it would reopen the 2008 TEP Rate Order for the sole purpose of evaluating TEP’s line extension policy. None of the parties to the 2008 TEP Rate Order objected. In July 2011, the ACC approved a policy similar to the one that was in place prior to the 2008 TEP Rate Order, whereby TEP will provide certain line extensions free of charge to customers. The capital costs incurred by TEP under this policy are recoverable from customers through future rates, subject to approval by the ACC. In 2011, TEP estimates it will incur capital expenditures of approximately $2 million for line extensions.

Sales to Mining Customers

In the first nine months of 2011, kWh sales to TEP’s mining customers increased 0.5% compared with the same period last year. Copper mines in TEP’s service area have increased their operations in response to high copper prices. TEP’s mining customers have indicated they are taking steps to increase production by either expanding their current operations or reopening nonoperational mine sites. Such efforts could lead to a 100 MW increase in TEP’s mining load over the next several years. The market price for copper and the ability to secure the necessary permits could affect the mining industry’s expansion plans.

Augusta Resources Corporation (Augusta) is seeking to develop a new mine near Tucson, Arizona, the Rosemont Copper Mine (Rosemont). Augusta is currently seeking governmental approvals and permits for the construction and operation of Rosemont. If Rosemont reaches full production, it would become TEP’s largest retail customer. TEP would serve approximately 100 MW of the mine’s total estimated load of approximately 110 MW.

TEP cannot predict if or when existing mines will expand operations or if new or reopened mines will commence operations.

San Juan Mine Fire

In September 2011, there was a fire at the underground mine that provides coal for San Juan. TEP owns approximately 20% of San Juan, which is operated by PNM. In October 2011, San Juan Coal Company, the mine owner and operator, indicated that mining operations could restart in April 2012.

PNM estimates that the current inventory of mined coal could supply the fuel requirements of San Juan for approximately eight and one-half months at forecasted consumption levels. Based on information we have received to date, we do not expect the mine fire to have a material effect on our financial condition, results of operations, or cash flows due to the inventories of previously mined coal available to supply San Juan. However, if the mine is shut down longer than currently anticipated, the owners of San Juan would need to consider alternatives for operating the unit, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time. 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 exposure to risk is mitigated because the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy are reported as either a regulatory asset, a regulatory liability or a component of Accumulated Other Comprehensive Income (AOCI) rather than in the income statement. See Note 9 for more information.

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:


Nine Months Ended September 30,	2011			2010
	-Millions of Dollars-
Net Cash Flows — Operating Activities (GAAP)	$	206		$	221
Amounts from Statements of Cash Flows:
Less: Capital Expenditures⁽¹⁾		(194	)		(223	)

Net Cash Flows after Capital Expenditures (Non-GAAP)*		12			(2	)
Amounts From Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations		(74	)		(56	)
Plus: Proceeds from Investment in Lease Debt		38			26

Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)*	$	(24	)	$	(32	)


(1)		The first nine months of 2010 includes a $51 million payment for the purchase of Sundt Unit 4 lease equity.


Nine Months Ended September 30,	2011			2010
	-Millions of Dollars-
Net Cash Flows — Operating Activities (GAAP)	$	206		$	221
Net Cash Flows — Investing Activities (GAAP)		(153	)		(198	)
Net Cash Flows — Financing Activities (GAAP)		(58	)		(22	)
Net Cash Flows after Capital Expenditures (Non-GAAP)*		12			(2	)
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)*		(24	)		(32	)


*		Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Capital Expenditures and Required Payments, both non- GAAP measures, 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 Available after Capital Expenditures and Required Payments 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 UniSource Energy.

Liquidity Outlook

Over the next twelve months, TEP expects to generate sufficient operating cash flows to fund a majority of its construction expenditures. Additional sources for funding such construction expenditures could include draws on the TEP Revolving Credit Facility, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy. 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 its revolving credit facility as needed to fund its business activities.

New Headquarters Building

Through September 2011, UniSource Energy has invested $59 million to acquire land and construct a new headquarters building. UniSource Energy has a remaining commitment of $10 million at September 30, 2011. TEP expects to purchase the land and building at cost from UniSource Energy in November 2011. Initially, TEP expects to fund such purchase by using its revolving credit facility.

Operating Activities

In the first nine months of 2011, net cash flows from operating activities were $15 million lower than in the first nine months of 2010 due primarily to:

	•		a $44 million increase in O&M costs due in part to higher generating plant outage costs, higher up-front incentive payments for customer-installed solar systems, higher DSM payments and timing differences in payments made under TEP’s retirement plan; and

	•		a $5 million increase in taxes other than income taxes paid;

			partially offset by

	•		a $13 million decrease in income taxes paid;

	•		a $13 million increase in cash receipts from electric sales, net of fuel and purchased power costs. This increase was due in part to higher sales tax collections from customers resulting from a 1% increase in Arizona’s sales tax rate and higher retail kWh sales to residential, commercial and mining customers compared with the first nine months of 2010.

Investing Activities

Net cash flows used for investing activities decreased by $45 million in the first nine months of 2011 compared with the same period last year. Proceeds from the return of investment in Springerville lease debt increased by $13 million in the first nine months of 2011 compared with the same period last year. Capital expenditures during the first nine months of 2011 were $29 million lower than in the same period last year.

TEP’s capital expenditures were $194 million in the first nine months of 2011, compared with $223 million in the same period last year. TEP’s capital expenditures in the first nine months of 2010 included the purchase of Sundt Unit 4 for $51 million. TEP’s estimated capital expenditures for 2011 are $369 million.

Financing Activities

In the first nine months of 2011, net cash from financing activities was $36 million lower than in the same period in 2010 due to: a $19 million decrease in proceeds from the issuance of long term debt; an $18 million increase in payments on capital lease obligations; a $15 million capital contribution from UniSource Energy in the first nine months of 2010 to help fund the purchase of Sundt Unit 4; and a $15 million decline in borrowings (net of repayments) under TEP’s revolving credit facility; partially offset by $30 million of dividends paid to UniSource Energy during the first nine months of 2010.

TEP Credit Agreement

The TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $341 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2014 and is secured by $541 million of Mortgage Bonds. As of September 30, 2011, there was $5 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 UniSource Energy. As of September 30, 2011, TEP was in compliance with the terms of the TEP Credit Agreement.

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 IDBs 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 September 30, 2011, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

Capital Contribution from UniSource Energy

In March 2010, UniSource Energy contributed $15 million of capital to TEP to help fund TEP’s purchase of Sundt Unit 4.

Interest Rate Risk

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 if interest rates increase. As of September 30, 2011, TEP had $365 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 rate payable under the indentures for the bonds is 10% on the $37 million of 2010 Coconino A Bonds and is 20% on the other $329 million in IDBs. However, $50 million of our variable rate debt has been hedged through a fixed-for-floating interest rate swap. During the first nine months of 2011, the average rates paid ranged from 0.05% to 0.34%, compared with a range of 0.17% to 0.33% during the same period in 2010. As of October 20, 2011, the average rate on the debt was 0.13%.

Capital Lease Obligations

As of September 30, 2011, TEP had $428 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease amounts in each of the obligations.

Capital Lease Obligation

Balance

Leases

As of September 30, 2011

Renewal/Purchase

-Millions of Dollars-

Expiration

Option

Springerville Unit 1⁽¹⁾

254

2015

Fair market value purchase option

Springerville Coal Handling Facilities Lease

2015

Fixed price purchase option of $120 million⁽²⁾

Springerville Common Facilities⁽³⁾

109

2017 and 2021

Fixed price purchase option of $106 million⁽²⁾

Total Capital Lease Obligations

428


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

(2)		TEP has agreed with Tri-State and SRP, the owners of Springerville Units 3 and 4, respectively, that if these leases are not renewed, it will exercise such purchase options. Tri-State and SRP will then be obligated to either (i) buy a portion of these facilities or (ii) continue making payments to TEP for the use of these facilities.

(3)		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.

Income Tax Position

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

Contractual Obligations

There have been no significant changes in TEP’s contractual obligations or other commercial commitments from those reported in our 2010 Annual Report on Form 10-K, other than the following obligations established in 2011:


Payment Due in Years											2016
Ending December 31,	2011		2012		2013		2014		2015		and after		Total
	-Millions of Dollars-
Purchase Obligations:
Coal	$	34	$	40	$	14	$	14	$	—	$	—	$	102
Transportation		3		4		4		4		4		8		27
Purchased Power¹		3		23		20		21		12		196		275
Solar Equipment		12		12		12		—		—		—		36

Total Additional Contractual Cash Obligations	$	52	$	79	$	50	$	39	$	16	$	204	$	440


¹		Purchased Power includes two long-term Power Purchase Agreements (PPAs) with renewable energy generation producers to meet compliance under the RES tariff. The facilities achieved commercial operation in 2011. TEP is obligated to purchase 100% of the output from these facilities. The table above includes estimated future payments based on expected power deliveries under these contracts through 2031. TEP has entered into additional long-term renewable PPAs to comply with the RES tariff; however, TEP’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

Dividends on Common Stock

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 Reimbursement Agreement and certain financial covenants. As of September 30, 2011, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 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 a net loss of $1 million in the third quarters of both 2011 and 2010. For the first nine months of 2011, UNS Gas reported net income of $6 million compared with net income of $5 million in the same period last year. The table below provides summary financial information for UNS Gas.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011		2010
	-Millions of Dollars-						-Millions of Dollars-
Gas Revenues	$	18		$	19		$	101	$	101
Other Revenues		1			—			2		2

Total Operating Revenues		19			19			103		103
Purchased Gas Expense		9			10			61		62
Other Operations and Maintenance Expense		6			6			19		19
Depreciation and Amortization		2			2			6		6
Taxes Other Than Income Taxes		1			1			2		2

Total Other Operating Expenses		18			19			88		89

Operating Income		1			—			15		14
Total Interest Expense		2			2			5		5
Income Tax Expense		—			(1	)		4		4

Net Income	$	(1	)	$	(1	)	$	6	$	5

The tables below include UNS Gas’ Therm sales and margin revenues for the three and nine months ended September 30, 2011 and 2010.


					Increase (Decrease)
Three Months Ended September 30,	2011		2010		Amount			Percent*
Energy Sales, Therms (in millions)
Gas Retail Sales:
Residential		5		5		—			0.4	%
Commercial		4		4		—			3.1	%
Industrial		1		—		1			37.2	%
Public Authorities		—		1		(1	)		(14.2	%)

Total Gas Retail Sales		10		10		—			2.1	%
Negotiated Sales Program (NSP)		6		9		(3	)		(34.7	%)

Total Gas Sales		16		19		(3	)		(15.8	%)


Gas Revenues (in millions):
Retail Margin Revenues:
Residential	$	6	$	6	$	—			1.8	%
Commercial		2		2		—			—
Industrial		—		—		—			—
Public Authorities		—		—		—			—

Total Retail Margin Revenues (Non-GAAP)**		8		8		—			1.4	%
Transport and NSP		4		5		(1	)		(25.0	%)
Retail Fuel Revenues		6		6		—			6.5	%

Total Gas Revenues (GAAP)	$	18	$	19	$	(1	)		(4.3	%)


					Increase (Decrease)
Weather Data:	2011		2010		Amount			Percent
Heating Degree Days
Three Months Ended September 30		242		224		18			8.0	%
10-Year Average		330		333		(3	)		(0.9	%)


*		Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

**		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. 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 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 operating expenses of our core utility business.

Retail Therm sales during the third quarter of 2011 increased by 2.1%, due in part to a 5.8% increase in Heating Degree Days compared with the third quarter of 2010. Retail margin revenues increased by 1.4%, or less than $1 million, compared with the third quarter of 2010.

UNS Gas supplies natural gas to some of its large transportation customers through a Negotiated Sales Program (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 that reduces the gas commodity price.


					Increase (Decrease)
Nine Months Ended September 30,	2011		2010		Amount			Percent*
Energy Sales, Therms (in millions)
Gas Retail Sales:
Residential		48		50		(2	)		(3.1	%)
Commercial		21		21		—			(0.3	%)
Industrial		2		1		1			22.0	%
Public Authorities		4		4		—			(4.5	%)

Total Gas Retail Sales		75		76		(1	)		(2.0	%)
Negotiated Sales Program (NSP)		19		22		(3	)		(8.4	%)

Total Gas Sales		94		98		(4	)		(3.4	%)


Gas Revenues (in millions):
Retail Margin Revenues:
Residential	$	28	$	28	$	—			0.4	%
Commercial		7		7		—			4.2	%
Industrial		—		—		—			—	%
Public Authorities		1		1		—			—	%

Total Retail Margin Revenues (Non-GAAP)**	$	36	$	36	$	—			1.1	%

Transport and NSP		14		14		—			(4.5	%)
Retail Fuel Revenues		51		51		—			0.6	%

Total Gas Revenues (GAAP)	$	101	$	101	$	—			0.2	%


					Increase (Decrease)
Weather Data:	2011		2010		Amount			Percent
Heating Degree Days
Nine Months Ended September 30		15,713		13,621		2,092			15.4	%
10-Year Average		12,730		12,741		(12	)		(0.1	%)


*		Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

**		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. 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 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 operating expenses of our core utility business.

Retail Therm sales during the first nine months of 2011 decreased by 2.0%. Retail margin revenues increased by 1.1%, or less than $1 million, during the first nine months of 2011 due in part to a base rate increase that was implemented in April 1, 2010.

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of Gas EE Standards may reduce energy consumption by UNS Gas’ retail customers. In addition, customers of UNS Gas have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas.

Rates

2010 UNS Gas Rate Order

Effective April 2010, UNS Gas implemented a base rate increase of $3 million, or 2%.

2011 UNS Gas Rate Filing

Due to increases in capital and operating costs, UNS Gas filed a general rate case with the ACC in April 2011 requesting higher base rates. The proposed rates include a higher fixed service charge and a decoupling mechanism to assist in recovering the company’s authorized fixed costs under the Gas EE Standards. The filing also requests a change in depreciation rates that, if approved, is expected to reduce annual depreciation expense by $1 million. The table below summarizes UNS Gas’ request.


Test year – 12 months ended Dec. 31, 2010		Requested by UNS Gas
Original cost rate base		$184 million
Revenue deficiency		$5.6 million
Total rate increase (over test year revenues)		3.8%
Cost of equity		10.5%
Actual capital structure		51% equity / 49% debt
Weighted average cost of capital		8.7%

On October 28, 2011, the ACC staff filed testimony that recommended a base revenue increase of approximately $2 million. Hearings before an ACC administrative law judge are scheduled to begin in early 2012, and the ACC could issue a final order during the first half of 2012.

Fair Value Measurements

UNS Gas’ exposure to risk is mitigated because it reports the change in the fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset, a regulatory liability, or a component of AOCI rather than in the income statement. See Note 9 for more information.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas expects operating cash flows to fund all of its construction expenditures during 2011. If natural gas prices rise and UNS Gas is not allowed to recover its gas costs on a timely basis, UNS Gas may require additional funding to meet its capital requirements. Sources of funding for 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 UniSource Energy. The base rate increase that took effect in April 2010 covers some, but not all, of UNS Gas’ higher costs and capital investments.

Cash Flows and Capital Expenditures

Cash Flows

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


Nine Months Ended September 30,	2011			2010
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	22		$	10
Investing Activities		(9	)		(6	)
Financing Activities		(10	)		(10	)

Net Increase (Decrease in Cash)		3			(6	)
Beginning Cash		29			31

Ending Cash	$	32		$	25

Operating Activities

UNS Gas’ operating cash flows were higher during the first nine months of 2011 than they were during the same period last year. Lower market prices for natural gas led to a decline in purchased energy costs and a decrease in cash payments (net of receipts) to gas supply and hedging counterparties.

Investing Activities

UNS Gas incurred capital expenditures of $10 million in the first nine months of 2011. Total capital expenditures for 2011 are estimated to be $12 million.

Financing Activities

UNS Gas issued $50 million of senior unsecured notes in August 2011, replacing a like amount of notes that matured on August 11, 2011. SeeSenior Unsecured Notes, Bond Issuance,below.

UNS Gas paid dividends of $10 million to UniSource Energy during the first nine months of 2011.

UNS Gas/UNS Electric Revolver

The UNS Gas/UNS Electric Revolver is a $100 million unsecured facility that expires in November 2014. Either company can borrow up to a maximum of $70 million so long as the combined amount borrowed by both companies does not exceed $100 million.

Each company is liable only for its own borrowings under the UNS Gas/UNS Electric Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric under the UNS Gas/UNS Electric Revolver.

The UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires that each borrower not exceed a maximum leverage ratio. Each borrower may pay dividends as long as it maintains compliance with the agreement. As of September 30, 2011, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.

UNS Gas 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 natural gas procurement and hedging activities. As of October 20, 2011, UNS Gas had no outstanding borrowings or letters of credit under 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. SeeItem 3. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Senior Unsecured Notes

UNS Gas has $100 million of senior unsecured notes outstanding, of which $50 million mature in 2015 and $50 million mature in 2026. The $50 million of senior unsecured notes maturing in 2026 were issued in August 2011. SeeNote Issuancebelow.

All of UNS Gas’ senior unsecured notes are guaranteed by UES. The note purchase agreements for UNS Gas restrict transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness. The agreements also contain a minimum net worth test. As of September 30, 2011, UNS Gas was in compliance with the terms of its note purchase agreements.

UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Gas may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.

Note Issuance

In August 2011, UNS Gas issued $50 million of 5.39% senior unsecured notes. The proceeds were used to pay off $50 million of senior unsecured notes that matured on August 11, 2011.

Contractual Obligations

In 2011, UNS Gas entered into new long-term purchase commitments for fuel with estimated minimum payment obligations of $3 million in both 2012 and 2013 and $2 million in 2014. There have been no other significant changes in UNS Gas’ contractual obligations or other commercial commitments from those reported in our 2010 Annual Report on Form 10-K.

Dividends on Common Stock

UNS Gas paid dividends to UniSource Energy of $10 million in both February 2011 and April 2010. UNS Gas’ ability to pay future dividends will depend on its 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 as long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test.

UNS ELECTRIC

RESULTS OF OPERATIONS

In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for $63 million on July 1, 2011. In accordance with accounting rules related to the transfer of a business held under common control, we reflect UNS Electric’s purchase of BMGS as if it occurred on January 1, 2009. The transaction had no impact on UniSource Energy’s consolidated financial statements for 2009 or 2010.

UNS Electric reported net income of $7 million in the third quarter of 2011, compared with net income of $5 million in the third quarter of 2010. The increase is due primarily to a rate increase that was implemented in October 2010. For the nine months ended September 30, 2011, UNS Electric reported net income of $14 million compared with net income of $12 million in the same period last year.

Results from the first nine months of 2010 included $3 million of pre-tax income related to a settlement with Arizona Public Service Company for refunds related to transactions with the California Power Exchange.

As with 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					Nine Months Ended
	September 30,					September 30,
	2011			2010		2011			2010
	-Millions of Dollars-					-Millions of Dollars-
Retail Electric Revenues	$	54		$	60	$	142		$	139
Wholesale Electric Revenues		13			13		28			22
Other Revenues		1			—		1			1

Total Operating Revenues		68			73		171			162
Purchased Energy Expense		41			41		94			92
Fuel Expense		3			5		6			10
Transmission Expense		4			4		9			9
Increase (Decrease) to reflect PPFAC Recovery		(5	)		—		(1	)		(8	)
Other Operations and Maintenance Expense		7			8		19			22
Depreciation and Amortization Expense		4			4		13			12
Taxes Other Than Income Taxes		1			1		3			3

Total Other Operating Expenses		55			63		143			140

Operating Income		13			10		28			22

Other Income		—			—		—			3
Total Interest Expense		2			2		5			5
Income Tax Expense		4			3		9			8

Net Income	$	7		$	5	$	14		$	12

The table below shows UNS Electric’s kWh sales and revenues for the third quarters of 2011 and 2010:


					Increase (Decrease)
Three Months Ended September 30,	2011		2010		Amount			Percent*
Energy Sales, kWh (in millions)
Electric Retail Sales:
Residential		299		301		(2	)		(0.9	%)
Commercial		173		181		(8	)		(4.6	%)
Industrial		61		62		(1	)		(0.9	%)
Mining		50		51		(1	)		(2.6	%)
Public Authorities		—		1		(1	)		(30.2	%)

Total Electric Retail Sales		583		596		(13	)		(2.2	%)


Retail Margin Revenues (in millions):
Retail Margin Revenues:
Residential	$	11	$	9	$	2			32.1	%
Commercial		8		7		1			5.5	%
Industrial		2		2		—			4.5	%
Mining		2		1		1			30.8	%
Public Authorities		—		—		—			—

Total Retail Margin Revenues (Non-GAAP)**	$	23	$	19	$	4			18.7	%
PPFAC Revenues		29		38		(9	)		(19.4	%)
RES & DSM Revenues		2		3		(1	)		(50.0	%)

Total Retail Revenues (GAAP)	$	54	$	60	$	(6	)		(8.7	%)


Weather Data:	2011		2010
Cooling Degree Days
Three Months Ended September 30		5,766		5,758	8	0.1	%
10-Year Average		5,469		5,433	36	0.7	%


*		Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

**		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 revenues collected from retail customers that are directly offset by expenses recorded in other line items. 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 operating expenses of our core utility business.

Total retail kWh sales in the third quarter of 2011 decreased by 2.2% compared with the same period last year. Retail margin revenues during the third quarter of 2011 increased by $4 million compared with the third quarter of 2010. The increase in retail margin revenues is due to the base rate increase that took effect in October 2010.

The table below shows UNS Electric’s kWh sales and revenues for the first nine months of 2011 and 2010:


					Increase (Decrease)
Nine Months Ended September 30,	2011		2010		Amount			Percent*
Energy Sales, kWh (in millions)
Electric Retail Sales:
Residential		652		652		—			(0.1	%)
Commercial		463		470		(7	)		(1.5	%)
Industrial		168		166		2			1.2	%
Mining		172		149		23			15.6	%
Public Authorities		1		2		(1	)		(22.2	%)

Total Electric Retail Sales		1,456		1,439		17			1.2	%


Electric Retail Revenues (in millions):
Retail Margin Revenues:
Residential	$	24	$	22	$	2			16.2	%
Commercial		22		20		2			8.4	%
Industrial		7		6		1			4.8	%
Mining		5		4		1			28.9	%
Other		—		—		—			(25.0	%)

Total Retail Margin Revenues (Non-GAAP)**	$	58	$	52	$	6			12.4	%
Retail Fuel Revenues		80		80		—			(2.0	%)
DSM and RES Revenues		4		7		(3	)		(33.8	%)

Total Retail Revenues (GAAP)	$	142	$	139	$	3			1.8	%


Weather – Cooling Degree Days	2011		2010
Nine Months Ended September 30		8,513		8,235	278		3.4	%
10-Year Average		8,434		8,462	(28	)	(0.3	%)


*		Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

**		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 revenues collected from retail customers that are directly offset by expenses recorded in other line items. 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 operating expenses of our core utility business.

Total retail kWh sales in the first nine months of 2011 increased by 1.2% compared with the same period last year. Mining kWh sales increased by 15.6% compared with the first nine months of 2010 due to increased production by UNS Electric’s two mining customers in response to strong copper and gold prices.

Total retail margin revenues increased by $6 million due primarily to a base rate increase that took effect in October 2010 and the increase in mining kWh sales described above.

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of 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.

2010 UNS Electric Rate Order

Effective October 1, 2010, UNS Electric implemented a base rate increase of $7.4 million, or 4%. The rate order also requires UNS Electric to file a rate case no later than 12 months after its purchase of BMGS from UED. SeeBlack Mountain Generating Station,below for more information.

Black Mountain Generating Station

In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. FERC approved the purchase in June 2011. In accordance with accounting rules related to the transfer of a business held under common control, we reflect UNS Electric’s purchase of BMGS as if it were a non-cash contribution on January 1, 2009. SeeInvesting Activities, below, for more information.

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 2011 through 2014 in solar photovoltaic projects. We estimate that each $5 million investment would build approximately 1.25 MW of solar capacity. The first such project is expected to be completed in 2011, and we expect UNS Electric will begin cost recovery through the RES in January 2012. In October 2011, ACC staff filed a recommendation that, if approved, could impact (i) the funding mechanism that allows UNS Electric to recover costs associated with company-owned solar projects and (ii) UNS Electric’s strategy for meeting the RES. The ACC is expected to issue a final ruling on this matter in the fourth quarter of 2011.

Fair Value Measurements

UNS Electric’s exposure to risk is mitigated because it reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset, a regulatory liability, or a component of AOCI rather than in the income statement. See Note 9 for more information.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric expects operating cash flows to fund a portion of its construction expenditures during 2011. Additional sources of funding for 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 UniSource Energy.

Cash Flows and Capital Expenditures

Cash Flows

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


Nine Months Ended September 30,	2011			2010
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	36		$	23
Investing Activities		(85	)		(17	)
Financing Activities		44			(7	)

Net Increase (Decrease in Cash)		(5	)		(1	)
Beginning Cash		11			10

Ending Cash	$	6		$	9

Operating Activities

Operating cash flows increased in the first nine months of 2011 due in part to higher fuel and purchased power cost recoveries from customers and a base rate increase that took effect in October 2010.

Investing Activities

UNS Electric had capital expenditures of $88 million in the first nine months of 2011 and forecasts total capital expenditures in 2011 of $104 million. These amounts reflect the transfer of BMGS from UED for $63 million, and are eliminated in consolidation at UniSource Energy. SeeBlack Mountain Generating Station, above, for more information.

On July 1, 2011, UNS Electric distributed proceeds to UED from a $20 million capital contribution from UniSource Energy, $13 million of cash on hand and $30 million of borrowings under the UNS Gas/UNS Electric Revolver as payment for BMGS. SeeBlack Mountain Generating Station, above, for more information.

UNS Gas/UNS Electric Revolver

SeeUNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolverabove 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 October 20, 2011, UNS Electric had $8 million of letters of credit issued under the UNS Gas/UNS Electric Revolver.

Interest Rate Risk

UNS Electric is subject to interest rate risk resulting from changes in the variable interest rates on borrowings under its revolving credit facility. If LIBOR or other benchmark interest rates increase, UNS Electric may be required to pay higher rates of interest on those borrowings. For more information seeItem 3. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Senior Unsecured Notes

UNS Electric has $100 million of senior unsecured notes outstanding, including $50 million of 6.50% notes due in 2015 and $50 million of 7.10% notes due August 2023. The notes are guaranteed by UES. The note purchase agreement for UNS Electric contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness. As of September 30, 2011, UNS Electric was in compliance with the terms of its note purchase agreement.

UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.

UNS Electric Credit Agreement

In August 2011, UNS Electric entered into a 4-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.25%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three month LIBOR rate on a $30 million notional amount over a four year period ending August 10, 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt in the balance sheet, is guaranteed by UES.

Contractual Obligations

In 2011, UNS Electric entered into the following new long-term, forward power purchase commitments in addition to those reported in our 2010 Annual Report on Form 10-K.


	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Long Term Debt	$	—	$	—	$	—	$	—	$	30	$	—	$	30
Purchased Power¹		1		20		24		35		3		46		129
Total	$	1	$	20	$	24	$	35	$	33	$	46	$	159


¹		Purchased Power includes a long-term Power Purchase Agreement (PPA) with a renewable energy generation producer to meet compliance under the RES tariff. The facility achieved commercial operation in September 2011. UNS Electric is obligated to purchase 100% of the output from this facility. The table above includes estimated future payments based on expected power deliveries under the contract through 2031. UNS Electric has entered into additional long-term renewable PPAs to comply with the RES tariff; however, UNS Electric’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

Dividends on Common Stock

As of September 30, 2011, UNS Electric had not paid any dividends. UNS Electric’s ability to pay dividends will depend on its 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 September 30, 2011, UNS Electric was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above.

OTHER NON-REPORTABLE BUSINESS SEGMENTS

RESULTS OF OPERATIONS

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	-Millions of Dollars-						-Millions of Dollars-
Millennium	$	1		$	(6	)	$	2		$	(9	)
UED		—			1			2			3
UniSource Energy Parent Company		(1	)		(1	)		(4	)		(3	)

Total Other	$	—		$	(6	)	$	—		$	(9	)

Millennium

Third Quarter

Millennium recorded net income of $1 million in the third quarter of 2011 related to a gain on the sale of a building. Millennium’s results in the third quarter of 2010 included $5 million of income tax expense related to the write-off of deferred tax assets and a $1 million after-tax impairment loss related to its investments.

Nine Months Ended September 30

Millennium recorded net income of $2 million in the first nine months of 2011, $1 million of which related to a gain on the sale of a building. Millennium’s results in the first nine months of 2010 include: $5 million of income tax expense related to the write-off of deferred tax assets; $4 million of after-tax impairment losses related to its investments; and an after-tax gain of less than $1 million related to the sale of an investment.

UED

UED recorded after-tax income of $1 million during the third quarter of 2010 related to the operation of BMGS. On July 1, 2011, UNS Electric completed the purchase of BMGS from UED. UED used the proceeds from the sale of BMGS to repay the $27 million outstanding under the UED Credit Agreement and to pay a $36 million dividend to UniSource Energy. SeeUNS Electric, Factors Affecting Results of Operations, Black Mountain Generating Station,above, for more information.

UniSource Energy Parent Company

UniSource Energy parent company expenses include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes and the UniSource Credit Agreement. In the first nine months of 2011, UniSource Energy had capital expenditures of $34 million related to the construction of a new headquarters building.

FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

Millennium is in the process of exiting its remaining investments, which may yield gains or losses. As of September 30, 2011, Millennium had assets of $18 million including a $15 million note receivable, deferred tax assets of $1 million, and cash and cash equivalents of $2 million.

In July 2011, Millennium sold a building for $2 million resulting in an after-tax gain of approximately $1 million.

Millennium’s financial assets and liabilities that are accounted for at fair value on a recurring basis as of September 30, 2011, contain $2 million of Cash Equivalents, which are valued based on observable market prices and are comprised of the fair value of money market funds.

CRITICAL ACCOUNTING ESTIMATES

There have been no significant changes in our accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2010.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The following recently issued accounting standards are not yet reflected in UniSource Energy’s and TEP’s financial statements:

The FASB issued authoritative guidance that will eliminate the current option to report other comprehensive income in the statement of changes in equity. An entity can elect to present items of net income and other comprehensive income in one continuous statement or in two separate but consecutive, statements. We will be required to comply in the first quarter of 2012. We are evaluating which presentation method to use.

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. UniSource 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 UniSource 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 UniSource Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UniSource Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed therein. We express our expectations, beliefs and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed inPart 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, including environmental legislation and renewable energy requirements; regional economic and market conditions that 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 the company’s 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; changes to long-term contracts; the cost of fuel and energy supplies; and performance of TEP’s generating plants.


ITEM 3.		— QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in this Item identifies material changes from information included inPart II, Item 7Ain UniSource Energy’s and TEP’s Annual Report on Form 10-K for the year ended December 31, 2010 in addition to the interim condensed consolidated financial statements and accompanying notes presented inPart I, Item 1andManagement’s Discussion and Analysis presented in Part I, Item 2of this Form 10-Q.

Interest Rate Risk

Long-Term Debt

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. As of September 30, 2011, TEP had $365 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 rate payable under the indentures for these bonds is 10% on $37 million of the 2010 Coconino A Bonds and 20% on the other $329 million in IDBs. During the first nine months of 2011, the average weekly interest rate ranged from 0.05% to 0.34%. Although short-term interest rates have been relatively low and stable during 2010 and 2011, TEP still may be subject to volatility in its tax-exempt variable rate debt. However, $50 million of our variable rate debt has been hedged through a fixed-for-floating interest rate swap. A 100-basis-point increase in average interest rates on this debt, over a twelve-month period, would result in a decrease in TEP’s pre-tax net income of approximately $3 million.

Commodity Price Risk — TEP

TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas and coal. This risk is mitigated through a PPFAC mechanism that fully recovers the actual retail fuel and purchased power costs from TEP’s retail customers on a timely basis. The commodity price risk from changes in the price of coal, electricity and emission allowances have not changed materially from the commodity price risks reported in our 2010 Annual Report on Form 10-K.

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, TEP recorded the following net unrealized gains:


Nine Months Ended September 30,	2011		2010
	-Millions of Dollars-
Unrealized Gains	$	3	$	4

The chart below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts.


	Unrealized Gain (Loss) of TEP’s
	Hedging and Trading Activities
	- Millions of Dollars -
	Maturity 0 – 6			Maturity 6 –			Maturity over 1			Total Unrealized
	months			12 months			yr.			Gain (Loss)
Source of Fair Value as of September 30, 2011
Prices actively quoted	$	(1	)	$	(3	)	$	(1	)	$	(5	)
Prices based on models and other valuation methods		—			1			1			2

Total	$	(1	)	$	(2	)	$	—		$	(3	)

Sensitivity Analysis of Derivatives

TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its derivative forward contracts. Unrealized gains and losses are recorded as either a regulatory asset or a regulatory liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. The chart below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%.


Change in Market Price as of September 30, 2011	10% Increase		10% Decrease
	-Millions of Dollars-
Non-Cash Flow Hedges
Forward gas contracts	$	3	$	(3	)
Forward power sales and purchase contracts		—		—


Cash Flow Hedges
Forward power purchase contracts		1		(1	)

Long-Term Wholesale Sales

Since June 1, 2011, TEP has been exposed to commodity price risk relating to changes in the market price of electricity as it relates to a long-term wholesale contract with SRP. Under terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, or $22 million annually, through May 31, 2011. Effective June 1, 2011, TEP no longer receives the monthly demand charge and SRP is required to purchase 73,000 MWh per month, or 876,000 MWh annually, based on an energy price at a slight discount to the Palo Verde Market Index. As of October 20, 2011, the average around-the-clock forward price of power on the Palo Verde Market Index for the balance of 2011 was approximately $28 per MWh and approximately $31 per MWh for the calendar year 2012.

The chart below summarizes the annual change in pre-tax income if the market price of power on the Palo Verde Market Index changes by $5 per MWh.


	Change in Per MWh Price
	$5 Increase		$5 Decrease
	-Millions of Dollars-
Change in Pre-Tax Income	$	4	$	(4	)

Commodity Price Risk — UNS Gas

UNS Gas is subject to commodity price risk, primarily from changes in the price of natural gas purchased for its customers. This risk is mitigated through the PGA mechanism, which provides an adjustment to UNS Gas’ retail rates to recover the actual costs of gas and transportation.

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, UNS Gas recorded the following net unrealized gains (losses):


Nine Months Ended September 30,	2011		2010
	-Millions of Dollars-
Unrealized Gains (Losses)	$	3	$	(6	)

For UNS Gas’ forward gas purchase contracts, a 10% decrease in market prices would result in a $3 million increase in unrealized net losses reported as net regulatory assets; a 10% increase in market prices would result in a $3 million decrease in unrealized net losses reported as net regulatory assets.

Commodity Price Risk — UNS Electric

UNS Electric is exposed to commodity price risk from changes in the price for electricity and natural gas. This risk is mitigated through a PPFAC mechanism that fully recovers the costs incurred on a timely basis.

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, UNS Electric recorded the following net unrealized gains (losses):


Nine Months Ended September 30,	2011		2010
	-Millions of Dollars-
Unrealized Gains (Losses)	$	1	$	(8	)

For UNS Electric’s forward power sales and purchase contracts, a 10% decrease in market prices would result in a $6 million increase in unrealized net losses reported as net regulatory assets; a 10% increase in market prices would result in a $6 million decrease in unrealized net losses reported as a reduction in regulatory assets.

For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in a $1 million increase in unrealized net losses reported as net regulatory assets; a 10% increase in market prices would result in a $1 million decrease in unrealized net losses reported as a reduction in regulatory assets.

Credit Risk

UniSource Energy is exposed to credit risk in its energy-related marketing, trading and hedging activities related to potential nonperformance by counterparties.

As of September 30, 2011, TEP’s total credit exposure related to wholesale marketing and gas hedging activities was approximately $17 million, including $4 million in exposure to non-investment grade counterparties. TEP’s $3 million exposure to one non-investment grade counterparty represented more than 10% of its total credit exposure.

As of September 30, 2011, TEP had posted no cash collateral and $1 million in letters of credit as credit enhancements with its counterparties and did not hold any collateral from counterparties.

As of September 30, 2011, UNS Gas had less than $1 million of counterparty credit exposure under its supply and hedging contracts.As of September 30, 2011, UNS Gas had no collateral posted as credit enhancements with its counterparties and did not hold any collateral from counterparties.

As of September 30, 2011, UNS Electric had $3 million of counterparty credit exposure under its supply and hedging contracts. As of September 30, 2011, UNS Electric had posted $8 million in letters of credit with counterparties. It had not posted cash collateral as a credit enhancement and had not collected any collateral margin from its counterparties.


ITEM 4.		— CONTROLS AND PROCEDURES

UniSource Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource 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 UniSource 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 UniSource 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, UniSource Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UniSource Energy’s and TEP’s disclosure controls and procedures are effective.

While UniSource 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 UniSource Energy’s or TEP’s internal control over financial reporting during the third quarter of 2011 that has materially affected, or is reasonably likely to materially affect, UniSource Energy’s or TEP’s internal control over financial reporting.

PART II — OTHER INFORMATION


ITEM 1.		— LEGAL PROCEEDINGS

See the legal proceedings described inItem 3. — Legal Proceedingsin our 2010 Annual Report on Form 10-K and in Note 6 and inItem 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 6 and Item 2 are incorporated herein by reference.


ITEM 1A.		— RISK FACTORS

The business and financial results of UniSource Energy and TEP are subject to numerous risks and uncertainties. The risks and uncertainties have not changed materially from those reported in our 2010 Annual Report on Form 10-K.


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

Issuer Purchases of Equity Securities — None.


ITEM 5.		— OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES

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


	Nine Months		Twelve Months
	Ended		Ended
	Sept. 30, 2011		Sept. 30, 2011
UniSource Energy		2.833		2.479

TEP		2.918		2.523

For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expense on indebtedness.

ENVIRONMENTAL MATTERS

Clean Air Act Requirements

TEP’s generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other atmospheric emissions. 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.

EPA Information Request

TEP has submitted its response to the request received in October 2010 from the EPA under Section 114 of the Clean Air Act for information regarding projects and operations at the Sundt Generating Station. TEP owns and operates all four units at Sundt. Units 1, 2 and 3 can be operated on either natural gas or diesel oil. Unit 4 can be operated on either natural gas or coal.

The EPA uses information obtained from such requests to determine if additional action is necessary. TEP can neither predict whether the EPA will take further action at Sundt nor project the impact of any such action.

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 October 2009, the EPA entered into a consent order through which it agreed to develop rules establishing standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units and to issue final rules by November 2011.

The EPA issued its proposed rule in March 2011. Depending on the terms of the EPA’s final rule, emission controls may be required at some or all of TEP’s coal-fired units by 2014 or later. Whether emission controls are required at a particular unit, the level of control required, and the cost to achieve that level of control will not be known until the rule has been promulgated. TEP submitted comments to the EPA on the proposed rule.

Navajo

Based on the EPA’s proposed 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.

Springerville

San Juan

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

Sundt

TEP does not anticipate the proposed EPA rule will have a material capital impact on Sundt Unit 4.

Four Corners

TEP is analyzing the potential impacts of the proposed EPA rule on Four Corners.

Climate Change

In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al v. EPA that carbon dioxide (CO₂) and other greenhouse gases (GHGs) are air pollutants under the Clean Air Act. In December 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 April 2010, triggering GHG permitting requirements for power plants under the Clean Air Act. As of January 2, 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.

While the debate over the direction of domestic climate policy continues on the national level, several states have developed state-specific policies or regional initiatives to reduce GHG emissions. In 2007, the governors of several western states, including the then-governor of Arizona, signed the Western Regional Climate Action Initiative (the Western Climate Initiative) which directed their respective states to develop a regional target for reducing greenhouse gases. The states in the Western Climate Initiative announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020. In 2008, the Western Climate Initiative participants submitted their design recommendation for the Western Climate Initiative cap-and-trade program for greenhouse gas emissions, with an implementation date set for 2012.

In February 2010, the current Arizona governor issued an executive order which, among other things, stated that Arizona will not implement the GHG cap-and-trade proposal advanced by the Western Climate Initiative. The executive order expires December 31, 2012.

In 2010, New Mexico adopted regulations limiting GHG emissions from power plants and providing for participation in the Western Climate Initiative. Several parties are attempting to modify or rescind these regulations. We cannot predict if, or when, these new regulations will impact the generating output or cost of operations at San Juan and Luna.

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.

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 is the lead regulatory agency for these plants in terms of regional haze planning.

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. TEP cannot predict the ultimate outcome of these matters.

San Juan

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO₂ and sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (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. Based on two recent cost analyses commissioned by PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $155 and $202 million.

Four Corners

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

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report being commissioned by the Department of Interior. The report will address potential energy, environmental and economic issues associated with regional haze rule compliance at Navajo. That report is due in December 2011. A final BART rule is expected later in 2012. If the EPA determines that 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 capital expenditures will 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.

Coal Combustion Residuals

In June 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 except San Juan, which is subject to separate regulations.

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. We do not know when the EPA will issue a final rule, including required compliance dates, and cannot predict the outcome of the EPA’s actions. The financial impact of this rulemaking to TEP, if any, cannot be determined at this time.

Ozone National Ambient Air Quality Standard

In September 2011, President Obama ordered the EPA to withdraw its reconsideration of the 2008 National Ambient Air Quality Standard for Ozone. The ozone standard is scheduled to be updated in 2013 as required by the Clean Air Act.


ITEM 6.		— EXHIBITS

See Exhibit Index.

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.


		UNISOURCE ENERGY CORPORATION
		(Registrant)

Date: October 31, 2011		/s/ Kevin P. Larson

		Kevin P. Larson
		Senior Vice President and Principal
		Financial Officer

		TUCSON ELECTRIC POWER COMPANY
		(Registrant)

Date: October 31, 2011		/s/ Kevin P. Larson

		Kevin P. Larson
		Senior Vice President and Principal
		Financial Officer

EXHIBIT INDEX


**4.1	—	Note Purchase Agreement, dated as of May 4, 2011, among UNS Gas, Inc., UniSource Energy Services, Inc., and a group of purchasers (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.1).

**4.2	—	Credit Agreement, dated as of August 10, 2011, among UNS Electric, Inc., UniSource Energy Services, Inc., and Union Bank, N.A., as Administrative Agent (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.2).

12(a)	—	Computation of Ratio of Earnings to Fixed Charges — UniSource Energy.

12(b)	—	Computation of Ratio of Earnings to Fixed Charges — TEP.

15	—	Letter regarding unaudited interim financial information.

31(a)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act — UniSource Energy, by Paul J. Bonavia.

31(b)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act — UniSource 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	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).

*101	—	The following materials from UniSource Energy Corporation’s and Tucson Electric Power Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (Extensible Business Reporting Language):

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

	(b)		Notes to Condensed Consolidated Financial Statements.


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

**		Previously filed as indicated and incorporated by reference.

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