UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2007

OR

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

For the transition period from _______________ to _____________.

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification Number
1-13739	UNISOURCE ENERGY CORPORATION (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ  85701 (520) 571-4000	86-0786732
1-5924	TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ  85701 (520) 571-4000	86-0062700

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 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.  Yes    X       No____

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

UniSource Energy Corporation Large Accelerated Filer ­­­ X  Accelerated Filer __ Non-accelerated filer __

Tucson Electric Power Company Large Accelerated Filer __ Accelerated Filer __ Non-accelerated filer  X 

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

UniSource Energy Corporation Yes No  X 

Tucson Electric Power Company Yes No  X 

At October 31, 2007, 35,338,420 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At October 31, 2007, 32,139,434 shares of Tucson Electric Power Company’s common stock, no par value, were outstanding, 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
	Comparative Condensed Consolidated Statements of Income		3
		Comparative Condensed Consolidated Statements of Cash Flows	4
		Comparative Condensed Consolidated Balance Sheets	5
		Condensed Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income	7
	Tucson Electric Power Company
		Comparative Condensed Consolidated Statements of Income	8
		Comparative Condensed Consolidated Statements of Cash Flows	9
		Comparative Condensed Consolidated Balance Sheets	10
		Condensed Consolidated Statement of Changes in Stockholder’s Equity and Comprehensive Income	12
	Notes to Condensed Consolidated Financial Statements		13
	Note 1.   Nature of Operations and Basis of Accounting Presentation		13
	Note 2.   Regulatory Matters		13
	Note 3.   Debt and Credit Facilities		17
	Note 4.   Business Segments		17
	Note 5.   Accounting for Derivative Instruments and Trading Activities		18
	Note 6.   Income and Other Taxes		20
	Note 7.   Commitments and Contingencies		22
	Note 8.   Employee Benefits Plans		24
	Note 9.   Share-Based Compensation Plans		25
	Note 10. UniSource Energy Earnings Per Share (EPS)		27
	Note 11. Discontinued Operations – Sale of Global Solar		28
	Note 12. New Accounting Pronouncements		28
	Note 13. Supplemental Cash Flow Information		30
	Note 14. Review by Independent Registered Public Accounting Firm		31
Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
	UniSource Energy Consolidated		32
		Overview of Consolidated Business	32
		Outlook and Strategies	32
		Results of Operations	33
		Contribution by Business Segment	34
		Liquidity and Capital Resources	34
	Tucson Electric Power Company		37
		Results of Operations	37
		Factors Affecting Results of Operations	43
		Liquidity and Capital Resources	48
	UNS Gas		51
		Results of Operations	51
		Factors Affecting Results of Operations	53
		Liquidity and Capital Resources	54
	UNS Electric		55
		Results of Operations	55
		Factors Affecting Results of Operations	57
		Liquidity and Capital Resources	58
	Other Non-Reportable Business Segments		59
	Results of Operations		59
	Critical Accounting Estimates		60

ii

	New Accounting Pronouncements	61
	Safe Harbor for Forward-Looking Statements	61
Item 3. – Quantitative and Qualitative Disclosures about Market Risk		62
Item 4. – Controls and Procedures		67
PART II – OTHER INFORMATION
Item 1. – Legal Proceedings		68
Item 1A. – Risk Factors		68
Item 5. – Other Information		68
	Non-GAAP Measures	68
	Ratio of Earnings to Fixed Charges	70
Item 6. Exhibits		71
Signatures		71
Exhibit Index		72

iii

DEFINITIONS

The abbreviations and acronyms used in the 2007 third quarter report on Form 10-Q are defined below:

­

1992 Mortgage	TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to The Bank of New York, successor trustee, as supplemented.
1992 Mortgage Bonds	Bonds issued under the 1992 Mortgage.
ACC	Arizona Corporation Commission.
AMT	Alternative Minimum Tax.
BMGS	Black Mountain Generating Station under development by UED.
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 MWs.
Citizens	Citizens Communications Company.
Common Stock	UniSource Energy’s common stock, without par value.
Company or UniSource Energy	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 daily low temperatures.
DSM	Demand side management.
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.
ESP	Energy Service Provider.
FAS 133	Statement of Financial Accounting Standards No. 133: Accounting for Derivative Instruments and Hedging Activities, as amended.
FERC	Federal Energy Regulatory Commission.
Fixed CTC	Competition Transition Charge of approximately $0.009 per kWh that is included in TEP’s retail rate for the purpose of recovering TEP’s $450 million TRA by December 31, 2008.
Four Corners	Four Corners Generating Station.
Global Solar	Global Solar Energy, Inc., a company that develops and manufactures thin-film photovoltaic cells.  Millennium sold its interest in Global Solar in March 2006.
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.
ICRA	Implementation Cost Regulatory Asset.
IRS	Internal Revenue Service.
kWh	Kilowatt-hour(s).
LIBOR	London Interbank Offered Rate.
Luna	Luna Energy Facility.
Mark-to-Market Adjustments	Forward energy sales and purchase contracts that are considered to be derivatives are adjusted monthly by recording unrealized gains and losses to reflect the market prices at the end of each month.
MEG	Millennium Environment Group, Inc., a wholly-owned subsidiary of Millennium, which manages and trades emission allowances and related financial instruments.
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy.
MMBtu	Million British Thermal Units.
MW	Megawatt(s).
MWh	Megawatt-hour(s).
Navajo	Navajo Generating Station.
PGA	Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers.
PPFAC	Purchased Power and Fuel Adjustment Clause.

iv

PWMT	Pinnacle West Marketing and Trading.
REST	Renewable Energy Standard and Tariff.
RUCO	Residential Utility Consumer Office.
Rules	Retail Electric Competition Rules.
Salt River Project	A public power utility serving more than 900,000 customers in Phoenix, Arizona.
San Juan	San Juan Generating Station.
Settlement Agreement	TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for electric retail competition and transition asset recovery.
SO2	Sulfur dioxide.
Springerville	Springerville Generating Station.
Springerville Coal Handling Facilities Leases	Leveraged lease arrangements relating to the coal handling facilities serving Springerville.
Springerville Common Facilities	Facilities at Springerville used in common with Springerville Unit 1 and Springerville Unit 2.
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.
SRP	Salt River Project Agricultural Improvement and Power District.
Sundt	H. Wilson Sundt Generating Station.
Sundt Unit 4	Unit 4 of the H. Wilson Sundt Generating Station.
TCRA	Termination Cost Regulatory Asset.
TEP	Tucson Electric Power Company, the principal subsidiary of UniSource Energy.
TEP Credit Agreement	Amended and Restated Credit Agreement between TEP and a syndicate of Banks, dated as of August 11, 2006.
TEP Revolving Credit Facility	Revolving credit facility under the TEP Credit Agreement.
Therm	A unit of heating value equivalent to 100,000 British thermal units (Btu).
TOU	Time of use.
TRA	Transition Recovery Asset, a $450 million regulatory asset established in TEP’s Settlement Agreement to be fully recovered by December 31, 2008.
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.
UES	UniSource Energy Services, Inc., an intermediate holding company established to own the operating companies (UNS Gas and UNS Electric) which acquired the Citizens’ Arizona gas and electric utility assets in 2003.
UES Settlement Agreement	An agreement with the ACC Staff dated April 1, 2003, addressing rate case and financing issues in the acquisition by UniSource Energy of Citizens’ Arizona gas and electric assets.
UniSource Credit Agreement	Amended and Restated Credit Agreement between UniSource Energy and a syndicate of banks, dated as of August 11, 2006.
UniSource Energy	UniSource Energy Corporation.
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens’ Arizona electric utility assets in 2003.
UNS Gas	UNS Gas, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens’ Arizona gas utility assets in 2003.
UNS Gas/UNS Electric Revolver	Revolving credit facility under the Amended and Restated Credit Agreement among UNS Gas and UNS Electric as borrowers, UES as guarantor, and a syndicate of banks, dated as of August 11, 2006.

v

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, 2007, the related condensed consolidated statements of income for each of the three-month and nine-month periods ended September 30, 2007 and 2006, the condensed consolidated statement of changes in stockholders' equity and comprehensive income for the nine-month period ended September 30, 2007, and the condensed consolidated statements of cash flows for the nine-month period ended September 30, 2007 and 2006.  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 have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, of cash flows, of capitalization, of changes in stockholders' equity and comprehensive income for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006; and in our report dated February 26, 2007, we expressed unqualified opinions thereon.  The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006, 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

Chicago, Illinois

November 1, 2007

1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of

Tucson Electric Power Company:

We have reviewed the accompanying condensed consolidated balance sheet of Tucson Electric Power Company and its subsidiaries (the Company) as of September 30, 2007, the related condensed consolidated statements of income for each of the three-month and nine-month periods ended September 30, 2007 and 2006, the condensed consolidated statement of changes in stockholders' equity and comprehensive income for nine-month period ended September 30, 2007, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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 have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, of cash flows, of capitalization, of changes in stockholder's equity and comprehensive income for the year then ended (not present herein), and in our report dated February 26, 2007, 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, 2006, 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

Chicago, Illinois

November 1, 2007

2

						PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended							Nine Months Ended
September 30,							September 30,
2007			2006				2007			2006
(Unaudited)							(Unaudited)
-Thousands of Dollars-							- Thousands of Dollars -
						Operating Revenues
$	320,238		$	298,641		Electric Retail Sales	$	765,450		$	728,697
	46,225			40,616		Electric Wholesale Sales		139,515			129,387
	15,967			20,615		Gas Revenue		100,927			109,150
	15,774			9,896		Other Revenues		39,925			23,352
	398,204			369,768		Total Operating Revenues		1,045,817			990,586
						Operating Expenses
	90,135			78,301		Fuel		223,423			197,660
	104,428			85,455		Purchased Energy		271,464			242,014
	60,226			59,856		Other Operations and Maintenance		194,346			175,406
	34,513			33,330		Depreciation and Amortization		103,494			96,767
	25,739			21,959		Amortization of Transition Recovery Asset		59,944			51,080
	11,555			10,232		Taxes Other Than Income Taxes		36,208			35,145
	326,596			289,133		Total Operating Expenses		888,879			798,072
	71,608			80,635		Operating Income		156,938			192,514
						Other Income (Deductions)
	3,756			4,582		Interest Income		12,656			14,651
	1,811			1,814		Other Income		7,455			5,436
	(2,291	)		(206	)	Other Expense		(4,542	)		(1,181	)
	3,276			6,190		Total Other Income (Deductions)		15,569			18,906
						Interest Expense
	18,468			18,855		Long-Term Debt		54,733			56,747
	16,112			17,974		Interest on Capital Leases		48,390			55,047
	-			1,080		Loss on Extinguishment of Debt		-			1,080
	1,355			4,303		Other Interest Expense		4,767			6,876
	(2,199	)		(1,304	)	Interest Capitalized		(5,228	)		(4,652	)
	33,736			40,908		Total Interest Expense		102,662			115,098
	41,148			45,917		Income from Continuing Operations before Income Taxes		69,845			96,322
	15,731			17,714		Income Tax Expense		27,678			38,630
	25,417			28,203		Income from Continuing Operations		42,167			57,692
	-			-		Discontinued Operations - Net of Tax		-			(2,669	)
$	25,417		$	28,203		Net Income	$	42,167		$	55,023
	35,514			35,308		Weighted-average Shares of Common Stock Outstanding (000)		35,469			35,223
						Basic Earnings (Loss) per Share
$	0.72		$	0.80		Income from Continuing Operations	$	1.19		$	1.64
	-			-		Discontinued Operations - Net of Tax		-			(0.08	)
$	0.72		$	0.80		Net Income	$	1.19		$	1.56
						Diluted Earnings (Loss) per Share
$	0.66		$	0.73		Income from Continuing Operations	$	1.13		$	1.53
	-			-		Discontinued Operations - Net of Tax		-			(0.07	)
$	0.66		$	0.73		Net Income	$	1.13		$	1.46
$	0.225		$	0.21		Dividends Declared per Share	$	0.675		$	0.63
See Notes to Condensed Consolidated Financial Statements.

3

UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
	2007			2006
	(Unaudited)
	-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	793,437		$	759,535
Cash Receipts from Electric Wholesale Sales		226,429			180,832
Cash Receipts from Gas Sales		135,886			139,334
Cash Receipts from Operating SPV Unit 3		28,440			2,132
Interest Received		18,349			21,345
Performance Deposits Receipts		7,554			15,283
Sale of Excess Emission Allowances		9,987			7,081
Income Tax Refunds Received		1,016			553
Other Cash Receipts		8,529			6,593
Purchased Energy Costs Paid		(354,410	)		(288,399	)
Fuel Costs Paid		(214,098	)		(184,417	)
Payment of Other Operations and Maintenance Costs		(126,019	)		(107,754	)
Taxes Paid, Net of Amounts Capitalized		(102,527	)		(98,886	)
Wages Paid, Net of Amounts Capitalized		(83,332	)		(77,429	)
Interest Paid, Net of Amounts Capitalized		(59,186	)		(58,504	)
Capital Lease Interest Paid		(53,482	)		(62,780	)
Income Taxes Paid		(20,923	)		(40,220	)
Performance Deposits Payments		(7,900	)		(9,617	)
Excess Tax Benefit from Stock Options Exercised		(443	)		(1,106	)
Other Cash Payments		(3,770	)		(3,575	)
Net Cash Used by Operating Activities of Discontinued Operations		-			(2,710	)
Net Cash Flows – Operating Activities		203,537			197,291
Cash Flows from Investing Activities
Capital Expenditures		(181,894	)		(158,755	)
Proceeds from Investment in Springerville Lease Debt		27,732			22,158
Proceeds from the Sale of Land and Buildings		2,524			428
Return of Investment from Millennium Energy Business		12			4,743
Other Cash Receipts		1,951			1,750
Payments for Investment in Springerville Lease Equity		-			(48,025	)
Sale of Subsidiary		-			16,000
Other Cash Payments		(2,864	)		(1,487	)
Investment in and Loans to Equity Investees		(632	)		(4,518	)
Net Cash Used by Investing Activities of Discontinued Operations		-			(46	)
Net Cash Flows - Investing Activities		(153,171	)		(167,752	)
Cash Flows from Financing Activities
Payments on Borrowings under Revolving Credit Facilities		(159,000	)		(119,000	)
Payments on Capital Lease Obligations		(71,533	)		(61,175	)
Common Stock Dividends Paid		(23,829	)		(14,715	)
Repayments of Long-Term Debt		(4,500	)		(88,000	)
Proceeds from Borrowings under Revolving Credit Facilities		160,000			155,000
Proceeds from Issuance of Long-Term Debt		-			30,000
Proceeds from Stock Options Exercised		1,689			3,682
Excess Tax Benefit from Stock Options Exercised		443			1,106
Other Cash Receipts		7,228			9,886
Payment of Debt Issue/Retirement Costs		(429	)		(1,898	)
Other Cash Payments		(5,452	)		(3,851	)
Net Cash Flows - Financing Activities		(95,383	)		(88,965	)
Net Decrease in Cash and Cash Equivalents		(45,017	)		(59,426	)
Cash and Cash Equivalents, Beginning of Year		104,241			144,679
Cash and Cash Equivalents, End of Period	$	59,224		$	85,253
See Note 13 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.

4

UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
	2007			2006
	(Unaudited)
ASSETS	- Thousands of Dollars -
Utility Plant
Plant in Service	$	3,485,678		$	3,410,638
Utility Plant under Capital Leases		702,337			702,337
Construction Work in Progress		197,912			135,431
Total Utility Plant		4,385,927			4,248,406
Less Accumulated Depreciation and Amortization		(1,536,414	)		(1,492,842	)
Less Accumulated Amortization of Capital Lease Assets		(515,080	)		(495,944	)
Total Utility Plant - Net		2,334,433			2,259,620
Investments and Other Property
Investments in Lease Debt and Equity		152,781			181,222
Other		68,741			66,194
Total Investments and Other Property		221,522			247,416
Current Assets
Cash and Cash Equivalents		59,224			104,241
Trade Accounts Receivable		125,720			124,789
Unbilled Accounts Receivable		58,648			58,499
Allowance for Doubtful Accounts		(18,221	)		(16,859	)
Materials and Fuel Inventory		82,938			73,628
Trading Assets - Derivative Instruments		18,120			26,387
Current Regulatory Assets		9,621			9,549
Deferred Income Taxes - Current		54,747			57,912
Income Tax Receivable		13,974			-
Interest Receivable - Current		3,016			7,782
Other		12,636			9,982
Total Current Assets		420,423			455,910
Regulatory and Other Assets
Transition Recovery Asset		41,682			101,626
Income Taxes Recoverable Through Future Revenues		31,045			34,749
Other Regulatory Assets		54,706			54,848
Other Assets		29,592			33,240
Total Regulatory and Other Assets		157,025			224,463
Total Assets	$	3,133,403		$	3,187,409
See Notes to Condensed Consolidated Financial Statements.
(Continued)

5

UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
	2007			2006
	(Unaudited)
CAPITALIZATION AND OTHER LIABILITIES	- Thousands of Dollars -
Capitalization
Common Stock	$	701,719		$	697,426
Accumulated Deficit		(8,879	)		(27,913	)
Accumulated Other Comprehensive Loss		(16,323	)		(15,364	)
Common Stock Equity		676,517			654,149
Capital Lease Obligations		528,896			588,771
Long-Term Debt		1,003,370			1,171,170
Total Capitalization		2,208,783			2,414,090
Current Liabilities
Current Obligations under Capital Leases		58,596			59,090
Borrowing Under Revolving Credit Facilities		16,000			50,000
Current Maturities of Long-Term Debt		204,300			6,000
Accounts Payable		79,100			102,829
Income Taxes Payable		-			16,429
Interest Accrued		25,884			52,392
Trading Liabilities - Derivative Instruments		8,208			16,537
Accrued Taxes Other than Income Taxes		49,101			35,431
Accrued Employee Expenses		19,227			22,886
Customer Deposits		21,372			19,767
Current Regulatory Liabilities		14,222			10,707
Other		7,124			3,852
Total Current Liabilities		503,134			395,920
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent		145,215			126,883
Pension and Other Post-Retirement Benefits		101,274			105,085
Regulatory Liability - Net Cost of Removal for Interim Retirements		92,317			85,394
Other Regulatory Liabilities		10,094			9,609
Other		72,586			50,428
Total Deferred Credits and Other Liabilities		421,486			377,399
Commitments and Contingencies (Note 7)
Total Capitalization and Other Liabilities	$	3,133,403		$	3,187,409
See Notes to Condensed Consolidated Financial Statements.
(Concluded)

6

UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
								Accumulated
	Common							Other			Total
	Shares		Common		Accumulated			Comprehensive			Stockholders'
	Issued*		Stock		Deficit			Loss			Equity
	(Unaudited)
	- Thousands of Dollars -
Balances at December 31, 2006		35,190	$	697,426	$	(27,913	)	$	(15,364	)	$	654,149
Adoption of FIN 48						696						696
Comprehensive Income (Loss):
2007 Year-to-Date Net Income		-		-		42,167			-			42,167
Unrealized Loss on Cash Flow Hedges
(net of $2,158 income taxes)		-		-		-			(3,291	)		(3,291	)
Reclassification of Unrealized Loss on
Cash Flow Hedges to Net Income
(net of $1,439 income taxes)		-		-		-			2,194			2,194
Employee Benefit Obligations
Amortization of net actuarial loss and prior service cost
included in net periodic benefit cost
(net of $90 income taxes)									138			138
Total Comprehensive Income												41,208
Dividends Declared		-				(23,829	)					(23,829	)
Shares Issued under Stock Compensation Plans		5										-
Shares Issued for Stock Options		100		1,689								1,689
Stock Award Compensation Expense				2,161								2,161
Tax Benefit Realized from Stock Options Exercised		-		443								443
Balances at September 30, 2007		35,295	$	701,719	$	(8,879	)	$	(16,323	)	$	676,517
* UniSource Energy has 75 million authorized shares of common stock.
See Notes to Condensed Consolidated Financial Statements.

7

TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended							Nine Months Ended
September 30,							September 30,
2007			2006				2007			2006
(Unaudited)							(Unaudited)
- Thousands of Dollars -							- Thousands of Dollars -
						Operating Revenues
$	266,466		$	248,188		Electric Retail Sales	$	635,818		$	605,215
	46,120			40,553		Electric Wholesale Sales		139,337			129,198
	16,255			9,352		Other Revenues		41,686			22,124
	328,841			298,093		Total Operating Revenues		816,841			756,537
						Operating Expenses
	90,135			78,302		Fuel		223,423			197,660
	58,094			36,012		Purchased Power		115,111			79,485
	47,845			47,337		Other Operations and Maintenance		159,569			139,331
	29,392			28,772		Depreciation and Amortization		88,033			83,504
	25,739			21,959		Amortization of Transition Recovery Asset		59,944			51,080
	9,616			8,218		Taxes Other Than Income Taxes		30,222			29,058
	260,821			220,600		Total Operating Expenses		676,302			580,118
	68,020			77,493		Operating Income		140,539			176,419
						Other Income (Deductions)
	3,092			3,864		Interest Income		10,496			12,454
	1,160			1,644		Other Income		3,913			4,018
	(2,048	)		(247	)	Other Expense		(3,725	)		(1,031	)
	2,204			5,261		Total Other Income (Deductions)		10,684			15,441
						Interest Expense
	12,651			12,965		Long-Term Debt		37,766			38,669
	16,105			17,960		Interest on Capital Leases		48,371			55,024
	-			685		Loss on Extinguishment of Debt		-			685
	1,062			3,986		Other Interest Expense		4,020			5,852
	(1,397	)		(1,197	)	Interest Capitalized		(3,264	)		(3,958	)
	28,421			34,399		Total Interest Expense		86,893			96,272
	41,803			48,355		Income Before Income Taxes		64,330			95,588
	15,844			18,754		Income Tax Expense		25,279			38,180
$	25,959		$	29,601		Net Income	$	39,051		$	57,408
See Notes to Condensed Consolidated Financial Statements.

8

TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
	2007			2006
	(Unaudited)
	-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	658,623		$	632,986
Cash Receipts from Electric Wholesale Sales		226,429			180,832
Cash Receipts from Operating SPV Unit 3		28,440			2,132
Interest Received		16,006			18,446
Sale of Excess Emission Allowances		9,987			7,081
Other Cash Receipts		5,888			4,720
Fuel Costs Paid		(214,099	)		(184,359	)
Purchased Power Costs Paid		(190,071	)		(129,453	)
Payment of Other Operations and Maintenance Costs		(116,657	)		(95,570	)
Taxes Paid, Net of Amounts Capitalized		(76,583	)		(72,958	)
Wages Paid, Net of Amounts Capitalized		(65,818	)		(60,488	)
Capital Lease Interest Paid		(53,464	)		(62,758	)
Interest Paid, Net of Amounts Capitalized		(39,159	)		(36,706	)
Income Taxes and Related Interest Paid		(23,609	)		(58,714	)
Other Cash Payments		(2,769	)		(1,690	)
Net Cash Flows – Operating Activities		163,144		$	143,501
Cash Flows from Investing Activities
Capital Expenditures		(123,352	)		(111,463	)
Payments for Investment in Springerville Lease Equity		-			(48,025	)
Proceeds from Investment in Springerville Lease Debt		27,732			22,158
Proceeds from Sale of Land		642			-
Other Cash Payments		(2,444	)		(1,004	)
Net Cash Flows - Investing Activities		(97,422	)	$	(138,334	)
Cash Flows from Financing Activities

     Payments on Borrowings under Revolving Credit Facility (134,000 ) (100,000 )

     Payments on Capital Lease Obligations (71,464 ) (61,111 )

     Proceeds from Borrowings under Revolving Credit Facility 120,000 105,000

Other Cash Receipts		11,206			13,368
Payment of Debt Issue/Retirement Costs		(415	)		(1,439	)
Other Cash Payments		(783	)		(863	)
Net Cash Flows - Financing Activities		(75,456	)		(45,045	)
Net Decrease in Cash and Cash Equivalents		(9,734	)		(39,878	)
Cash and Cash Equivalents, Beginning of Year		19,711			53,433
Cash and Cash Equivalents, End of Period	$	9,977		$	13,555
See Note 13 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.

9

TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
	2007			2006
	(Unaudited)
ASSETS	- Thousands of Dollars -
Utility Plant
Plant in Service	$	3,085,103		$	3,035,494
Utility Plant under Capital Leases		701,631			701,631
Construction Work in Progress		126,377			92,125
Total Utility Plant		3,913,111			3,829,250
Less Accumulated Depreciation and Amortization		(1,480,200	)		(1,446,229	)
Less Accumulated Amortization of Capital Lease Assets		(514,701	)		(495,634	)
Total Utility Plant - Net		1,918,210			1,887,387
Investments and Other Property
Investments in Lease Debt and Equity		152,781			181,222
Other		33,586			30,161
Total Investments and Other Property		186,367			211,383
Current Assets
Cash and Cash Equivalents		9,977			19,711
Trade Accounts Receivable		104,549			97,512
Unbilled Accounts Receivable		46,068			35,115
Allowance for Doubtful Accounts		(16,646	)		(16,303	)
Intercompany Accounts Receivable		17,411			16,329
Materials and Fuel Inventory		73,225			63,629
Current Regulatory Assets		9,259			9,549
Income Tax Receivable		16,714			-
Deferred Income Taxes - Current		53,537			57,151
Interest Receivable - Current		3,016			7,782
Trading Assets - Derivative Instrument		4,244			15,447
Other		11,254			8,833
Total Current Assets		332,608			314,755
Regulatory and Other Assets
Transition Recovery Asset		41,682			101,626
Income Taxes Recoverable Through Future Revenues		31,045			34,749
Other Regulatory Assets		49,435			51,594
Other Assets		19,752			21,569
Total Regulatory and Other Assets		141,914			209,538
Total Assets	$	2,579,099		$	2,623,063
See Notes to Condensed Consolidated Financial Statements.
(Continued)

10

TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,	December 31,
	2007	2006
	(Unaudited)
CAPITALIZATION AND OTHER LIABILITIES	- Thousands of Dollars -
Capitalization
Common Stock	$         795,971	$         795,971
Capital Stock Expense	(6,357)	(6,357)
Accumulated Deficit	(179,893)	(219,640)
Accumulated Other Comprehensive Loss	(16,219)	(15,260)
Common Stock Equity	593,502	554,714
Capital Lease Obligations	528,620	588,424
Long-Term Debt	682,870	821,170
Total Capitalization	1,804,992	1,964,308
Current Liabilities
Current Obligations under Capital Leases	58,502	58,999
Current Maturities of Long-Term Debt	138,300	-
Borrowing Under Revolving Credit Facility	16,000	30,000
Accounts Payable	60,513	69,019
Intercompany Accounts Payable	11,466	10,743
Income Taxes Payable	-	8,409
Interest Accrued	23,530	45,613
Accrued Taxes Other than Income Taxes	40,944	27,227
Accrued Employee Expenses	17,428	21,102
Trading Liabilities - Derivative Instruments	3,341	11,163
Other	15,823	14,278
Total Current Liabilities	385,847	296,553
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent	163,627	155,253
Regulatory Liability - Net Cost of Removal for Interim Retirements	85,362	79,876
Pension and Other Post-Retirement Benefits	96,239	99,832
Other	43,032	27,241
Total Deferred Credits and Other Liabilities	388,260	362,202
Commitments and Contingencies (Note 7)
Total Capitalization and Other Liabilities	$      2,579,099	$      2,623,063
See Notes to Condensed Consolidated Financial Statements.
(Concluded)

11

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, 2006	$	795,971	$	(6,357	)	$	(219,640	)	$	(15,260	)	$	554,714
Adoption of FIN 48							696						696
Comprehensive Income:
2007 Year-to-Date Net Income		-		-			39,051			-			39,051
Unrealized Loss on Cash Flow Hedges
(net of $2,158 income taxes)		-		-			-			(3,291	)		(3,291	)
Reclassification of Unrealized Loss on
Cash Flow Hedges to Net Income
(net of $1,439 income taxes)		-		-			-			2,194			2,194
Employee Benefit Obligations
Amortization of net actuarial loss and prior service cost
included in net periodic benefit cost
(net of $90 income taxes)										138			138
Total Comprehensive Income													38,092
Balances at September 30, 2007	$	795,971	$	(6,357	)	$	(179,893	)	$	(16,219	)	$	593,502
See Notes to Condensed Consolidated Financial Statements.

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Unaudited

NOTE 1.  NATURE OF OPERATIONS AND BASIS OF ACCOUNTING PRESENTATION

UniSource Energy Corporation (UniSource Energy) is a holding company that has no significant operations of its own.  Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities.  UniSource Energy owns the common stock of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy Development Company (UED).

TEP, a regulated public utility, is UniSource Energy’s largest operating subsidiary and represented approximately 82% of UniSource Energy’s assets as of September 30, 2007.  TEP generates, transmits and distributes electricity to approximately 395,000 retail electric customers (389,000 retail customers as of September 30, 2006) in a 1,155 square mile area in Southern Arizona.  TEP also sells electricity to other utilities and power marketing entities primarily located in the Western U.S.  In addition, TEP operates Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State).

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 144,000 retail customers (142,000 retail customers as of September 30, 2006) in Mohave, Yavapai, Coconino, and Navajo counties in Northern Arizona, as well as Santa Cruz County in Southeast Arizona.  UNS Electric is an electric transmission and distribution company with approximately 90,000 retail customers (87,000 retail customers as of September 30, 2006) in Mohave and Santa Cruz counties.

Millennium invests in unregulated energy related businesses.  On March 31, 2006, UniSource Energy completed the sale of all of the capital stock of Global Solar, Inc. (Global Solar), Millennium’s largest subsidiary, to a third party.  See Note 11.

UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that, subject to approval, is expected to provide energy to UNS Electric.

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 (SEC) interim reporting requirements which do not include all the disclosures required by accounting principles generally accepted in the United States of America (GAAP) for audited annual financial statements.  The year-end condensed balance sheet data was derived from audited financial statements, but does not include disclosures required by GAAP for audited annual financial statements.  This quarterly report should be reviewed in conjunction with UniSource Energy and TEP’s 2006 Annual Report on Form 10-K.

Weather, among other factors, causes seasonal fluctuations in TEP, UNS Gas and UNS Electric’s sales; therefore, quarterly results are not indicative of annual operating results.  UniSource Energy and TEP have made reclassifications to the prior year financial statements for comparative purposes.  These reclassifications had no effect on Net Income.

NOTE 2.  REGULATORY MATTERS

ACCOUNTING FOR RATE REGULATION

TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies.  Sometimes these principles, such as Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), require special accounting treatment for regulated companies to show the effect of regulation.  For example, the ACC may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that they charge these expenses to customers in the future.  In this situation, FAS 71 requires that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until they are allowed to charge their customers.  TEP, UNS Gas and UNS Electric then

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

amortize these items as expense as they recover these charges from customers.  Similarly, certain revenue items may be deferred as regulatory liabilities, which are also eventually amortized to the income statement as rates to customers are reduced.

The conditions a regulated company must satisfy to apply the accounting policies and practices of FAS 71 include:

· an independent regulator sets rates;

· the regulator sets the rates to recover specific costs of providing service; and

· the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.

TEP RATES AND REGULATION

Future Implications of Discontinuing Application of FAS 71

Upon approval of the Settlement Agreement in 1999, TEP discontinued regulatory accounting under FAS 71 for its generation operations.  TEP continues to apply FAS 71 to its transmission and distribution operations.  TEP regularly assesses whether it can continue to apply FAS 71 to these operations.  If TEP stopped applying FAS 71, it would write-off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement.  Based on the regulatory asset balances, net of regulatory liabilities, at September 30, 2007, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $28 million.  While regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if TEP stopped applying FAS 71.

TEP Settlement Agreement

In 1999, the ACC approved the rules for the introduction of retail electric competition in Arizona (Rules), as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.

The Rules and the Settlement Agreement established:

· a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure;

· the recovery through rates during the transition period of $450 million of stranded generation costs through a Fixed Competition Transition Charge (Fixed CTC);

· capped rates for TEP retail customers through 2008;

· an ACC interim review of TEP retail rates in 2004;

· unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services;

· a process for ESPs to become licensed by the ACC to sell generation services at market prices to TEP retail customers;

· access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs);

· transmission and distribution services would remain subject to regulation on a cost of service basis; and

· beginning in 2009, TEP’s generation would be market-based and its retail customers would pay the market rate for generation services.

In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC.  While TEP’s filing did not propose any change in retail rates, the filing, with a test year ended December 31, 2003, showed that TEP was experiencing a revenue deficiency of $111 million, reflecting the need for an increase in retail rates of 16%.

TEP Rate Proposal Filing

In April 2006, the ACC ordered that a procedure be established to allow for a review of:

· the TEP Settlement Agreement and its effect on how TEP’s rates for generation services will be determined after December 31, 2008;

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

· TEP’s proposed amendments to the TEP Settlement Agreement; and

· Demand-Side Management (DSM), Renewable Energy Standards Tariffs (REST), and Time of Use Tariffs (TOU).

In July 2007, as required by the ACC, TEP filed the following rate proposal methodologies to establish new retail rates for TEP beginning in January 2009:

(1) Market-based generation and cost of service for transmission and distribution, showing a revenue deficiency of $172 million, reflecting an overall increase of approximately 22% over current retail rates.

(2) Cost-of-service for generation, transmission and distribution showing a revenue deficiency of $181 million, reflecting an overall increase of approximately 23% over current retail rates.

(3) Hybrid methodology with cost of service for generation, transmission and distribution. However, certain generation assets would be excluded from cost of service, showing a revenue deficiency of $117 million, reflecting an overall increase of approximately 15% over current retail rates.

Based on the TEP Settlement Agreement, TEP believes it is entitled to charge market-based generation service rates starting in 2009.

The ACC ordered that the Rate Case hearing for TEP start in May 2008.

Renewable Energy Standard and Tariff

In June 2007, the Arizona Attorney General certified the Renewable Energy Standard and Tariff rules (REST) approved by the ACC in November 2006.  The REST rules require TEP to generate or purchase 1.75% of its total annual retail energy requirements from renewable energy technologies in 2008.  This requirement gradually increases to 15% by 2025.  Currently, TEP generates 0.5% from renewable energy.  The REST rules provide guidance that the incremental costs to meet the REST rules can be recovered from retail customers through a surcharge on their bills.  In October 2007, TEP filed its proposed 5 year plan to meet the REST requirements.  TEP’s filing includes a proposed tariff to recover the estimated $24 million of incremental cost required to meet the REST rules during 2008.  The ACC must approve the 5 year plan, including the tariff, before it becomes effective.

UNS GAS RATES AND REGULATION

Energy Cost Adjustment Mechanism: Purchased Gas Adjuster (PGA)

UNS Gas’ retail rates include a PGA mechanism intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor.  All purchased gas commodity costs, including transportation, increase the PGA bank, a balancing account.  UNS Gas recovers these costs or returns amounts over-collected from/to ratepayers through a PGA mechanism.  The PGA mechanism includes the following two components:

(1) The PGA factor, computed monthly, subject to limitations, equals a base cost of gas of $0.40 per therm, or $4.00 per MMBtu, plus the difference between the twelve month rolling weighted average cost of gas over the base cost.

(2) When ACC-designated under- or over-recovery trigger points of $6.2 million and $4.5 million, respectively, are met, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a period deemed appropriate by the ACC.

In September 2007, the ACC increased the PGA credit on customer bills during the period October 2007 through April 2008 so that UNS Gas could refund up to $4.5 million of over-recovered gas costs.  The increased credit primarily results from a recent rate settlement in which a gas supplier must refund $2 million to UNS Gas.  The increased credit allows UNS Gas to pass the refund along to its customers.

At September 30, 2007, UNS Gas had over recovered its costs by $14 million on an accrual (GAAP) basis (PGA bank), of which $11 million was on a billed basis. The PGA bank is shown on the balance sheet as Current Regulatory Liabilities.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

Future Implications of Discontinuing Application of FAS 71

UNS Gas regularly assesses whether it can continue to apply FAS 71 to its regulated operations.  If UNS Gas stopped applying FAS 71, UNS Gas would write-off the related balance of its regulatory assets as an expense and write-off its regulatory liabilities as income on its income statement.  Based on the regulatory asset and liability balances, if UNS Gas had stopped applying FAS 71, it would have recorded an extraordinary after-tax gain of $10 million at September 30, 2007.  Discontinuing application of FAS 71 would not affect UNS Gas’ cash flows.

General Rate Case Filing

In July 2006, UNS Gas filed a general rate case (on a cost of service basis) with the ACC requesting a total rate increase of 7% to cover a revenue deficiency of $9 million.  This increase is necessary because of the growth in UNS Gas’ service territory and the related increase in capital expenditures and operating costs.

UNS Gas also requested modifications to its PGA mechanism to help address customer pricing issues posed by volatile gas prices, customer pricing that is inconsistent with the actual cost of gas, and the potential for over- or under-collections to result in the accumulation of large bank balances.

In October 2007, the ALJ issued a recommended opinion and order in the UNS Gas rate case.  The ALJ recommends a revenue increase of $5 million, compared with UNS Gas’ request of $9 million. The recommendation also included an 8.3% return on an original rate base cost of $154 million.  UNS Gas had requested an 8.8% return on an original rate base cost of $162 million.  The ALJ recommended the new rates go into effect on December 1, 2007.  The ACC is scheduled to consider the UNS Gas rate case in an open meeting on November 8, 2007.

UNS Gas has deferred $0.9 million of rate case preparation costs as a regulatory asset on its balance sheet.  As part of the UNS Gas rate case opinion, the ALJ recommended recovery of only $0.3 million for rate case costs.  UNS Gas is contesting the disallowance of the costs and believes the $0.9 million is probable of recovery.  However, should the final ACC Order provide for recovery of less than $0.9 million, UNS Gas would immediately expense the difference between the $0.9 million recorded and the recoverable amount.

UNS ELECTRIC RATES AND REGULATION

Energy Cost Adjustment Mechanism: Purchased Power Fuel Adjustment Clause (PPFAC)

UNS Electric’s retail rates include a PPFAC adjustor rate, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under- or over-recovery of costs.  The ACC approved a PPFAC surcharge of $0.01825 plus a base rate of $0.05194 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWMT.

At September 30, 2007, UNS Electric had over-recovered its costs by $9 million on an accrual (GAAP) basis, $3 million of which was on a billed basis.  This is shown on the balance sheet as Over Recovered Purchased Power Costs.

Future Implications of Discontinuing Application of FAS 71

UNS Electric regularly assesses whether it can continue to apply FAS 71 to its regulated operations.  If UNS Electric stopped applying FAS 71, it would write-off the related balances of its regulatory assets as an expense and would write-off its regulatory liabilities as income on its income statement.  Based on the regulatory asset and liability balances, if UNS Electric had stopped applying FAS 71, it would have recorded an extraordinary after-tax gain of $9 million at September 30, 2007.  Discontinuing application of FAS 71 would not affect UNS Electric’s cash flows.

General Rate Case Filing

In December 2006, UNS Electric filed a general rate case (on a cost of service basis) with the ACC requesting a total rate increase of 5.5% to cover a revenue deficiency of $9 million.  The increase is necessary because of the growth in UNS Electric’s service territory and the related increase in capital expenditures and operating costs.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

UNS Electric expects the ACC to rule on its rate case in early 2008.

UNS Electric also requested that a new PPFAC surcharge take effect when the current power supply agreement with PWMT expires in May 2008.

Renewable Energy Standard and Tariff

UNS Electric must also meet the newly enacted REST rules described above under TEP RATES AND REGULATION.  In October 2007, UNS Electric filed its proposed 5 year plan to meet the REST requirements, including a proposed tariff to recover the estimated $4 million of incremental cost during 2008.  The ACC must approve the 5 year plan, including the tariff, before it becomes effective.

NOTE 3.  DEBT AND CREDIT FACILITIES

UNS GAS/UNS ELECTRIC REVOLVING CREDIT AGREEMENT

In August 2006, UNS Gas and UNS Electric amended their unsecured revolving credit agreement (the UNS Gas/UNS Electric Revolver).  The amendment reduced the interest rate payable on borrowings, increased the revolving credit facility to $60 million from $40 million, and extended the maturity from April 2008 to August 2011.  Either UNS Gas or UNS Electric may borrow up to a maximum of $45 million, so long as the combined amount borrowed does not exceed $60 million.  The ACC approved the increase in the amount and term of the UNS Gas/UNS Electric Revolver in March 2007.

At September 30, 2007, UniSource Energy and UNS Electric had borrowings under their respective revolving credit facilities of $54 million that were excluded from Current Liabilities and presented as Long-Term Debt, as UniSource Energy and UNS Electric have the ability and the intent to have outstanding borrowings under their respective revolving credit facilities for the next twelve months.  At December 31, 2006 UNS Electric had borrowings under their Revolving Credit Facilities of $19 million that were excluded from Current Liabilities and presented as Long-Term Debt.

NOTE 4.  BUSINESS SEGMENTS

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

(1) TEP, a vertically integrated electric utility business, is UniSource Energy’s largest subsidiary.

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

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

The UniSource Energy, UES and Millennium holding companies, UED, and several other subsidiaries and equity investments, which are not considered reportable segments, are included in Other.  Other also includes the discontinued operations of Global Solar.  As discussed in Note 11, at March 31, 2006, Millennium sold all of the common stock of Global Solar and the results of operations of Global Solar are reported as discontinued operations for all periods presented.  Through affiliates, Millennium holds investments in several unregulated energy and emerging technology companies.  UED facilitated the expansion of Springerville Generating Station and is currently developing BMGS, a 90 MW gas turbine project in Northern Arizona.

Reconciling adjustments consist of the elimination of intercompany activity.  During the three months ended September 30, 2007 and September 30, 2006, Millennium subsidiaries recorded revenue from transactions with TEP of $3 million.  During the nine months ended September 30, 2007 and September 30, 2006, Millennium subsidiaries recorded revenue from transactions with TEP of $11 million and $10 million, respectively.  TEP’s related expense is reported in Other Operations and Maintenance expense on its income statement.  Millennium’s revenue and TEP’s related expense are eliminated in UniSource Energy consolidation.  In addition, during the three months ended September 30, 2007 and September 30, 2006, TEP recorded revenue from providing support services to UNS Gas and UNS Electric of $2 million and $1 million, respectively.  During the nine months ended September 30, 2007 and September 30, 2006, TEP recorded revenue from providing support services to UNS Gas and Electric of $5 million and $2 million, respectively. UNS Gas’ and Electric’s related expense is reported in Other

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

Operations and Maintenance expense on its income statement. Other significant reconciling adjustments include the elimination of investments in subsidiaries held by UniSource Energy and reclassifications of deferred tax assets and liabilities.

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

	Reportable Segments													UniSource
	TEP		UNS Gas			UNS Electric		Other			Reconciling Adjustments			Energy Consolidated
Income Statement	-Millions of Dollars-
Three months ended September 30, 2007:
Operating Revenues - External	$	327	$	17		$	54	$	-		$	-		$	398
Operating Revenues - Intersegment		2		-			-		3			(5	)		-
Income (Loss) from Continuing     Operations Before Income Taxes		42		(4	)		5		(2	)		-			41
Net Income (Loss)		26		(2	)		3		(2	)		-			25
Three months ended September 30, 2006:
Operating Revenues - External	$	298	$	21		$	51	$	-		$	-		$	370
Operating Revenues - Intersegment		1		-			-		4			(5	)		-
Income (Loss) from Continuing     Operations Before Income Taxes		48		(3	)		4		(3	)		-			46
Net Income (Loss)		30		(2	)		2		(2	)		-			28
Nine months ended September 30, 2007:
Operating Revenues - External	$	812	$	103		$	131	$	-		$	-		$	1,046
Operating Revenues - Intersegment		5		-			-		12			(17	)		-
Income (Loss) from Continuing     Operations Before Income Taxes		64		2			8		(4	)		-			70
Net Income (Loss)		39		1			5		(3	)		-			42
Nine months ended September 30, 2006:
Operating Revenues - External	$	754	$	111		$	125	$	-		$	-		$	990
Operating Revenues - Intersegment		2		-			-		11			(13	)		-
Income (Loss) from Continuing     Operations Before Income Taxes		96		3			7		(10	)		-			96
Discontinued Operations – Net of Tax		-		-			-		(3	)		-			(3	)
Net Income (Loss)		57		2			4		(8	)		-			55

Balance Sheet
Total Assets, September 30, 2007	$	2,579	$	242	$	226	$	1,064	$	(978	)	$	3,133
Total Assets, December 31, 2006		2,623		253		195		1,038		(922	)		3,187

 

NOTE 5.  ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND TRADING ACTIVITIES

TEP INTEREST RATE SWAP

In June 2006, TEP entered into an interest rate swap to reduce the risk of unfavorable changes in variable interest rates related to changes in LIBOR.  The swap has the effect of converting approximately $36 million of variable rate lease payments for the Springerville Common Facilities Leases to a fixed rate through January 1, 2020.  The swap is designated as a cash flow hedge for accounting purposes.  The changes in interest payments related to changes in LIBOR were completely offset by the interest rate swap in the first nine months of 2007.  At September

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

30, 2007, the fair value of the loss position related to the swap was approximately $2 million and is recorded in Other Liabilities. The unrealized loss is recorded in Accumulated Other Comprehensive Income, a component of Common Stock Equity.  Amounts in Accumulated Other Comprehensive Income will be reclassified to Interest on Capital Leases over the term of the Springerville Common Facilities Leases.  We expect less than $1 million to be reclassified into earnings over the next 12 months.

TEP FUEL AND POWER TRANSACTIONS

TEP enters into forward contracts to purchase or sell energy to supply retail customer needs, to take advantage of favorable market opportunities and to reduce exposure to energy price risk. In addition, TEP purchases all of its gas requirements at spot market prices.  To minimize price risk on these purchases, TEP enters into price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices.

Depending on the transaction characteristics, TEP applies one of the following accounting treatments to its derivatives.

· Normal Purchase and Sale - TEP enters into energy contracts for the physical delivery or sale of power to support its retail load requirements.  These contracts qualify as “normal sales and purchases” and are therefore not required to be marked-to-market.

· Cash Flow Hedges - TEP enters into gas swap agreements and forward power contracts to hedge the cash flow risk associated with TEP’s summer load requirements and its forecasted excess generation. Changes in fair value of these instruments are recorded as unrealized gains and losses in Other Comprehensive Income. At September 30, 2007, the contracts accounted for as cash flow hedges will settle through the third quarter of 2010.  There were no gains or losses recognized in Net Income related to hedge ineffectiveness because all cash flow hedges are considered to be effective. Unrealized gains and losses are reclassified into earnings when the hedged transactions settle or terminate.

· Mark-to-Market Transactions - The change in fair value (mark-to-market) of forward power contracts is recorded in Net Income. These derivatives include, but are not limited to, contracts for the purchase and sale of electricity with the intent of optimizing market opportunities, subject to specified risk parameters established and monitored by UniSource Energy’s Risk Management Committee.

The net unrealized gains and losses from TEP’s derivative activities were as follows:

Cash Flow Hedges

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	-Millions of Dollars-
Gain on Forward Power Sales & Purchases	$	1		$	6		$	-		$	7
Loss on Gas Price Swaps		(3	)		(1	)		(6	)		(15	)
Pre-Tax Gain (Loss) Recorded in OCI	$	(2	)	$	5		$	(6	)	$	(8	)
After Tax Gain (Loss) on Cash Flow Hedges Recorded in OCI	$	(1	)	$	3		$	(3	)	$	(5	)

  Reclassification of Unrealized Loss on Cash Flow Hedges to Net Income $ 7 $ 1 $ 4 $ 1

Mark-to-Market Transactions

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007			2006
	-Millions of Dollars-
Gain (Loss) on Forward Power Sales	$	-	$	6		$	7		$	7
Gain (Loss) on Forward Power Purchases		-		(5	)		(7	)		(6	)
Pre-Tax Gain Recorded in Earnings	$	-	$	1		$	-		$	1

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

The fair values of TEP’s fuel and power related derivative assets and liabilities were as follows:

	September 30,2007						December 31, 2006
	Mark-to-Market Contracts			Cash Flow Hedges			Mark-to-Market Contracts			Cash Flow Hedges
	-Millions of Dollars-
Derivative Assets – Current	$	3		$	2		$	9		$	6
Derivative Liabilities – Current		(2	)		(2	)		(9	)		(3	)
Net Current Derivative Assets	$	1		$	-		$	-		$	3
Derivative Liabilities – Noncurrent	$	-		$	-		$	-		$	(1	)

Amounts presented as Cash Flow Hedges, Derivative Assets – Current and Derivative Liabilities – Current, are expected to be reclassified into earnings within the next twelve months.

UNS ELECTRIC POWER SUPPLY TRANSACTIONS

UNS Electric

UNS Electric entered into forward contracts, for periods of one to five years, beginning in June 2008, to purchase energy to supply retail customer needs for the period after the full-requirements supply agreement with PWMT expires in May 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric has hedged a portion of its total natural gas exposure from gas-indexed purchase power agreements that begin in June 2008 with fixed price contracts.  In addition, UNS Electric began hedging a portion of its anticipated natural gas exposure from plant fuel for the period June 2008 and beyond.

The fair value of the derivative assets and liabilities was a $3 million net asset at September 30, 2007 and December 31, 2006.  Effective December 31, 2006, UNS Electric received an accounting order from the ACC which allows UNS Electric to defer the unrealized gains and losses on the balance sheet as a regulatory asset or liability.  Prior to receiving the accounting order, UNS Electric recorded less than $1 million in Other Comprehensive Income and in the income statement for the three and nine months ended September 30, 2006.  The net regulatory liability at September 30, 2007 and at December 31, 2006 was $3 million.

MEG TRADING TRANSACTIONS

MEG trades Emission Allowances and related instruments; however, its current activities consist of managing a small number of remaining positions which are expected to close by early 2008.  MEG marks its trading positions to market on a daily basis using actively quoted prices obtained from brokers and options pricing models for positions that extend through 2007.

For each of the three and nine months ended September 30, 2007, and comparable 2006 periods, MEG reported a net loss from trading activities of less than $1 million.

The fair values of MEG’s derivative assets and liabilities were as follows:

	September 30,	December 31,
	2007	2006
	-Millions of Dollars-
Trading Assets – Current	$  11	$  11
Trading Liabilities – Current	(5)	(5)
Net Current Trading Assets	$    6	$    6

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

NOTE 6.  INCOME AND OTHER TAXES

INCOME TAXES

The differences between the income tax expense (benefit) reflected on the income statements and the amount obtained by multiplying pre-tax income by the U.S. statutory federal income tax rate of 35% were as follows:

	UniSource Energy
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				-Thousands of Dollars -
Federal Income Tax Expense at Statutory Rate	$	14,401		$	16,071		$	24,446		$	33,713
State Income Tax Expense, Net of Federal Deduction		1,893			2,112			3,213			4,430
Depreciation Differences (Flow Through Basis)		696			662			2,087			1,987
Amortization of Excess Deferred Income Tax		21			(90	)		(107	)		(270	)
Tax Credits		(1,739	)		(127	)		(2,017	)		(381	)
Valuation Allowance		-			(120	)		-			(120	)
Other		459			(794	)		56			(729	)
Total Federal and State Income Tax Expense Before Discontinued Operations	$	15,731		$	17,714		$	27,678		$	38,630

	TEP
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				-Thousands of Dollars -
Federal Income Tax Expense at Statutory Rate	$	14,631		$	16,924		$	22,516		$	33,456
State Income Tax Expense, Net of Federal Deduction		1,923			2,224			2,959			4,396
Depreciation Differences (Flow Through Basis)		696			662			2,087			1,987
Amortization of Excess Deferred Income Tax		21			(90	)		(107	)		(270	)
Tax Credits		(1,739	)		(127	)		(2,017	)		(381	)
Valuation Allowance		-			(120	)		-			(120	)
Other		312			(719	)		(159	)		(888	)
Total Federal and State Income Tax Expense	$	15,844		$	18,754		$	25,279		$	38,180

ADOPTION OF FIN 48

FIN 48, Accounting for Uncertainty in Income Taxes – an interpretation of FAS 109 (FIN 48), issued July 2006, requires us to determine whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position.  Only tax positions that meet the “more-likely-than-not” threshold on a reporting date may be recognized in the financial statements. In May 2007, the Financial Accounting Standards Board issued a Staff Position on FIN 48 (FIN 48-1) to provide guidance as to when a tax position is effectively settled.  We considered this guidance in determining whether or not a tax position may be recognized in the financial statements.

As a result of adopting FIN 48 on January 1, 2007, TEP recorded an increase to beginning retained earnings of less than $1 million for the cumulative effect of applying FIN 48.  TEP estimates its net liability for uncertain tax positions is $7 million (reflecting a $13 million uncertain tax liability and a $6 million uncertain tax receivable).  As a

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

result of applying FIN 48, TEP reclassified the $7 million from a current income tax payable to a noncurrent liability.  For the three and nine months ended September 30, 2007, there were no changes to the net unrecognized tax liability.  If TEP recognized the unrecognized tax benefit of $7 million at September 30, 2007, there would be no impact on TEP’s effective tax rate.

TEP and UniSource Energy recognize interest accrued related to income tax positions in interest expense and penalties, if any, in operating expense.  Tax years 2002 through 2006 are open under Federal, Arizona and New Mexico statutes.

OTHER TAX MATTERS

On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets.  We also used the new accounting method on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.

In 2005, the Internal Revenue Service (IRS) issued a ruling which questions the ability of electric and gas utilities to use the new accounting method.  As a result, TEP, UNS Gas and UNS Electric amended their 2003 and 2004 tax returns to remove the benefit previously claimed using the new accounting method.   In December 2006, the IRS issued a final notice disallowing the use of the accounting method.  We filed a protest in March 2007 and have begun settlement discussions with the IRS.

NOTE 7.  COMMITMENTS AND CONTINGENCIES

TEP  COMMITMENTS

In July 2007, TEP entered into power supply agreements for the period June through September 2008 with prices indexed to natural gas prices.  TEP estimates its minimum payments under these contracts to be $8 million based on natural gas prices as of September 30, 2007.

In July 2007, TEP entered into an agreement to purchase 75,000 tons of coal from the McKinley Mine for the period August to December 2007.  TEP estimates the minimum payments under this contract to be $2 million in 2007.

In May 2007, TEP entered into a pipeline capacity contract for the period May 2007 through April 2008.  TEP expects the reservation charges under this contract to approximate $3 million in 2007 and $1 million in 2008.

In March 2007, TEP entered into a one-year gas transportation agreement.  TEP expects the minimum payments under this contract to be less than $1 million in 2007 and less than $0.3 million in 2008.

Termination of Power Purchases from Tri-State

Tri-State leases Springerville Unit 3, a 400 MW coal-fired generating facility at TEP’s existing Springerville Generating Station, from a financial owner.  TEP provides operating, maintenance and other services to Springerville Unit 3 under a 99-year operating agreement subject to cancellation by either party with 30 days notice.  Also, TEP purchased 100 MW of Tri-State system wide capacity for the period September 2006 through July 31, 2007 when Tri-State elected to terminate the purchase agreement.

UNS ELECTRIC COMMITMENTS

In 2006 and 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric estimates its future minimum payments under these contracts to be $48 million in 2008, $59 million in 2009, $38 million in 2010, $15 million in 2011, $8 million in 2012, and $8 million thereafter based on natural gas prices as of September 30, 2007.

UNS GAS COMMITMENTS

In June 2007, UNS Gas entered into a pipeline capacity agreement for the period March 2008 through February 2020.  UNS Gas’ annual demand charge under this contract approximates $1 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

TEP CONTINGENCIES

Claims Related to San Juan Coal Company

San Juan Coal Company, the coal supplier to San Juan, through leases with the federal government and the State of New Mexico, owns coal interests with respect to an underground mine.  Certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties in the area of the underground mine.  These gas producers allege that San Juan Coal Company’s underground coal mining operations have or will interfere with their gas production and will reduce the amount of natural gas that they would otherwise be entitled to recover.  San Juan Coal Company has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity was close enough to warrant shutting down the well.  These settlements, however, do not resolve all potential claims by gas producers in the underground mine area.  TEP cannot estimate the outcome of any future claims by these gas producers on the cost of coal at San Juan.

Litigation and Claims Related to Navajo Generating Station

In 2004, Peabody Western Coal Company (Peabody), the coal supplier to the Navajo Generating Station, 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 and breach of the coal supply agreement.  Because TEP owns 7.5% of the Navajo Generating Station, its share of the current claimed damages would be approximately $35 million.  TEP believes these claims are without merit and intends to continue to contest them.

Postretirement Benefit Costs at Navajo Generating Station

Peabody contends that the Navajo Generating Station participants are responsible under the coal supply agreements for postretirement benefit costs payable to the coal supplier’s employees.  In 1996, SRP filed a lawsuit in Maricopa County Superior Court on behalf of the participants at Navajo Generating Station, including TEP, seeking declaratory judgment that the participants are not responsible for these costs.  The Navajo Generating Station participants and Peabody continue to discuss a potential settlement.  We expect resolution of this matter in 2008.

Environmental Reclamation at Remote Generating Stations

TEP currently pays on-going reclamation costs related to the coal mines which supply the remote generating stations, and it is probable that TEP will have to pay a portion of final reclamation costs upon mine closure.  When a reasonable estimate of final reclamation costs is available, the liability will be recognized as a cost of coal over the remaining term of the corresponding coal supply agreement.  TEP estimates its undiscounted final reclamation liability to be $47 million at the end of the useful lives of the generating stations, and the present value of TEP’s liability for final reclamation approximates $13 million at the expiration dates of the coal supply agreements in 2011 through 2017.

Amounts recorded for final reclamation are subject to various assumptions, such as estimating the costs of reclamation, estimating 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 term.  TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition occurs over the remaining terms of its coal supply agreements.

TEP Wholesale Accounts Receivable and Allowances

TEP’s Accounts Receivable from Electric Wholesale Sales includes $16 million of receivables at September 30, 2007 and December 31, 2006 related to sales to the California Power Exchange (CPX) and the California Independent System Operator (CISO) in 2001 and 2000.  TEP’s Allowance for Doubtful Accounts on the balance sheet includes $13 million at September 30, 2007 and December 31, 2006 related to these sales.  There are several outstanding legal issues, complaints and lawsuits concerning the California energy crisis related to the FERC, wholesale power suppliers, Southern California Edison Company, Pacific Gas and Electric Company, the

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

CPX and the CISO.  We cannot predict the outcome of these issues or lawsuits.  We believe, however, that TEP is adequately reserved for its transactions with the CPX and the CISO.

RESOLUTION OF TEP CONTINGENCIES

Litigation and Claims Related to San Juan Generating Station

A third party filed a claim with the Environmental Protection Agency (EPA) that San Juan contaminated water resources as a result of disposing of fly ash in the surface mine pits adjacent to the generating station.  However, the EPA rejected this claim and no longer lists San Juan as a responsible party.  TEP owns 50% of San Juan Units 1 and 2, which equates to 19.8% of the total San Juan Generating Station.

GUARANTEES AND INDEMNITIES

In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis.  The most significant of these guarantees are:

· UES’ guarantee of senior unsecured notes issued in 2003 by UNS Gas ($100 million) and UNS Electric ($60 million),

· UES’ guarantee of a $60 million unsecured revolving credit agreement for UNS Gas and UNS Electric,

· UniSource Energy’s guarantee of approximately $5 million in natural gas transportation and supply payments in addition to building lease payments for UNS Gas.

To the extent liabilities exist under these contracts, the liabilities are included in our consolidated balance sheets.

In addition, we have indemnified the purchasers of interests in certain investments from additional taxes due for years before the sale of such investments.  The terms of the indemnifications do not include a limit on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations.  We have not made any payments under the terms of these indemnifications to date.

We believe that the likelihood UniSource Energy or UES would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.

NOTE 8.  EMPLOYEE BENEFITS PLANS

PENSION BENEFIT PLANS

TEP, UNS Gas and UNS Electric maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees.  Benefits are based on years of service and the employee's average compensation.  TEP, UNS Gas and UNS Electric fund the plans by contributing at least the minimum amount required under IRS regulations. Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by IRS benefit or compensation limitations.

OTHER POSTRETIREMENT BENEFIT PLANS

TEP provides limited health care and life insurance benefits for retirees.  All regular employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.  UNS Gas and UNS Electric provide postretirement medical benefits for current retirees and a small group of active employees. The majority of UNS Gas and UNS Electric employees do not participate in the postretirement medical plan.

The ACC allows TEP, UNS Gas and UNS Electric to recover postretirement costs through rates only as benefit payments are made to or on behalf of retirees.  The postretirement benefits are currently funded entirely on a pay-as-you-go basis.  Under current accounting guidance, TEP, UNS Gas and UNS Electric cannot record a regulatory asset for the excess of expense calculated per Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, over actual benefit payments.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

COMPONENTS OF NET PERIODIC BENEFIT COST

The components of net periodic benefit costs were as follows:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	September 30,						September 30,
	2007			2006			2007		2006
				-Millions of Dollars -
Components of Net Periodic Benefit Cost
Service Cost	$	2		$	2		$	-	$	1
Interest Cost		3			3			1		1
Expected Return on Plan Assets		(4	)		(3	)		-		-
Prior Service Cost Amortization		-			-			-		-
Recognized Actuarial Loss		1			-			-		-
Net Periodic Benefit Cost	$	2		$	2		$	1	$	2

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				-Millions of Dollars -
Components of Net Periodic Benefit Cost
Service Cost	$	6		$	6		$	1		$	2
Interest Cost		9			9			3			3
Expected Return on Plan Assets		(11	)		(10	)		-			-
Prior Service Cost Amortization		1			1			(1	)		(1	)
Recognized Actuarial Loss		2			2			-			1
Net Periodic Benefit Cost	$	7		$	8		$	3		$	5

NOTE 9.  SHARE-BASED COMPENSATION PLANS

Under the 2006 Omnibus Stock and Incentive Plan, the Compensation Committee of the UniSource Energy Board of Directors may issue various types of share-based compensation, including stock options, restricted shares/units, and performance shares.  The total number of shares which may be awarded under the Plan cannot exceed 2.25 million shares.  As of September 30, 2007, the total number of shares awarded under the 2006 Omnibus Stock and Incentive Plan was 0.5 million shares.

STOCK OPTIONS

On March 20, 2007, the Compensation Committee of the UniSource Energy Board of Directors granted 184,260 stock options to certain officers with an exercise price of $37.88 per share.   Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant and expire on the tenth anniversary of the grant.  Compensation expense is recorded on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures.  For awards granted to retirement eligible officers, compensation expense is recorded immediately.  Certain stock option awards accrue dividend equivalents that are paid in cash on the earlier of the date of exercise of the underlying option or the date the option expires.  Compensation expense is recognized as dividends are paid.

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option pricing model with the assumptions noted in the following table.  The expected term of options granted was estimated using a “simplified” method which considers the 3 year vesting period and the contractual term.  The risk-free rate is based on the rate available on a U.S. Treasury Strip with a maturity equal to the expected term of the option at the time of the grant.  Expected volatility was based on historical volatility for UniSource Energy’s stock for the past 6 years, the expected term.  The expected dividend yield on a share of stock was calculated using the historical dividend yield with the implicit assumption that current dividend yields will continue in the future.

	2007 Grant
Expected term (years)	6
Risk-free rate	4.4%
Expected volatility	20.2%
Expected dividend yield	2.4%
Weighted-average grant-date fair value of options granted	$8.13

A summary of stock option activity follows:

	Nine Months Ended September 30, 2007
	Total Stock Options Outstanding		Non-Vested Stock Options
		Weighted		Weighted
		Average		Average
		Exercise		Grant Date
	Shares	Price	Shares	Value
Options Outstanding, December 31, 2006	1,388,001	$18.59	193,737	$7.38
Granted	184,260	$37.88	184,260	$8.13
Exercised (or Vested)	(100,386)	$16.82	(65,706)	$7.39
Forfeited	(436)	$12.28	-	-
Options Outstanding, September 30, 2007	1,471,439	$21.13	312,291	$7.83
Options Exercisable, September 30, 2007	1,159,148	$17.39
Weighted Average Remaining Contractual Life at September 30, 2007				4.8 years
Weighted Average Remaining Contractual Life of Exercisable Shares at September 30, 2007				3.7 years

Exercise prices for stock options outstanding and exercisable as of September 30, 2007 are summarized as follows:

Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of  Shares	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price	Number of Shares	Weighted-Average Exercise Price
$11.00 - $15.56	502,235	2.2 years	$14.30	502,235	$14.30
$16.78 - $18.84	574,540	4.3 years	$18.02	574,540	$18.02
$30.55 - $37.88	394,664	8.9 years	$34.35	82,373	$31.76

PERFORMANCE SHARES

On March 20, 2007, the Compensation Committee of the UniSource Energy Board of Directors granted 37,270 performance share awards (targeted shares) to certain officers at a grant date fair value of $35.56 per share (market price of $37.88 less the present value of expected dividends of $2.32).  The performance share awards

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

will be paid out in shares of UniSource Energy Common Stock based on UniSource Energy’s performance over the performance period of January 1, 2007 through December 31, 2009.

In May 2006, 45,520 performance share awards (targeted shares) were granted to certain officers at a grant date fair value of $28.39 per share (market price of $30.55 less the present value of expected dividends of $2.16).  The performance share awards will be paid out in shares of UniSource Energy Common Stock based on UniSource Energy's performance over the period of January 1, 2006 through December 31, 2008.

The performance criteria specified in the awards is determined based on targeted UniSource Energy cumulative Diluted Earnings per Share and cumulative Cash Flow from Operations during the performance period.  The performance shares vest ratably over the performance period and any unearned awards are forfeited.  Compensation expense equal to the fair market value on the grant date less the present value of expected dividends is recognized over the vesting period if it is probable that the performance criteria will be met.

RESTRICTED STOCK UNITS

In the second quarter of 2007, the Compensation Committee of the UniSource Energy Board of Directors granted 17,858 stock units at a weighted average fair value of $37.30 per share to non-employee directors.  In 2006, we granted 16,362 stock unit awards to non-employee directors at a fair value of $30.63 per share on the grant date.  The restricted stock units vest in one year or immediately upon death, disability, or retirement.  In the January following the year the person is no longer a Director, Common Stock shares will be issued for the vested stock units.

SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units)

TEP recorded compensation expense of $1 million for the three months ended September 30, 2007 and 2006; and recorded $2 million for the nine months ended September 30, 2007 and 2006.  UniSource Energy reflected the same amounts as TEP.  We did not capitalize any share-based compensation costs.

At September 30, 2007, the total unrecognized compensation cost related to non-vested share-based compensation was $3 million, which will be recorded as compensation expense over the remaining vesting periods through March 2010. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at September 30, 2007 was 2 million.

NOTE 10.  UNISOURCE ENERGY EARNINGS PER SHARE (EPS)

Basic EPS is computed by dividing Net Income by the weighted average number of common shares outstanding during the period.  Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options, contingently issuable shares under equity-based awards or common shares that would result from the conversion of convertible notes.  The numerator in calculating diluted earnings per share is Net Income adjusted for the interest on convertible notes (net of tax) that would not be paid if the notes were converted to common shares.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	- In Thousands -				- In Thousands -
Numerator:
Net Income	$	25,417	$	28,203	$	42,167	$	55,023
Assumed Conversion of Convertible Senior Notes – reduced interest expense (after-tax)		1,097		1,097		3,292		3,292
Adjusted Numerator	$	26,514	$	29,300	$	45,459	$	58,315
Denominator:
Weighted-average Shares of Common Stock Outstanding:
Common Shares Issued		35,286		35,108		35,250		35,028
Fully Vested Deferred Stock Units		228		200		219		195
Total Weighted-average Shares of Common Stock Outstanding		35,514		35,308		35,469		35,223
Effect of Dilutive Securities:
Convertible Senior Notes		4,000		4,000		4,000		4,000
Options and Stock Issuable under the Share-based Compensation Plans		528		609		583		592
Total Shares		40,042		39,917		40,052		39,815

Stock options to purchase 0.2 million shares of Common Stock were outstanding during the three and nine months ended September 30, 2007 and 2006, respectively, but were excluded from the computation of diluted EPS because the stock option’s exercise price was greater than the average market price of the Common Stock.

NOTE 11.  DISCONTINUED OPERATIONS – SALE OF GLOBAL SOLAR

On March 31, 2006, UniSource Energy sold all of the capital stock of Global Solar to a third party.  UniSource Energy received $16 million in cash as part of the transaction; a portion of the proceeds was used to satisfy $10 million of secured promissory notes held by a UniSource Energy subsidiary.  In addition to the cash purchase price, UniSource Energy received a ten-year option to purchase between 5% and 10% of the common stock of Global Solar.  The option is only exercisable after March 2013 or upon certain events including a sale of all or substantially all of the assets of Global Solar, a merger, a change of control transaction, an initial public offering of Global Solar common stock or the payment by Global Solar of dividends in excess of specified amounts.  For accounting purposes, no value was assigned to this repurchase option.

The following summarizes the amounts included in Discontinued Operations – Net of Tax for the nine months ended September 30, 2006:

	-Millions of Dollars-
Revenues from Discontinued Operations	$ 1
Loss from Discontinued Operations	$(4)
Loss on Sale of Discontinued Operations	(1)
Loss from Discontinued Operations Before Income Taxes	(5)
Income Tax Benefit	(2)
Discontinued Operations – Net of Tax	$(3)

NOTE 12.  NEW ACCOUNTING PRONOUNCEMENTS

The FASB recently issued the following Statements of Financial Accounting Standards (FAS) and FASB Staff Positions (FSP):

· FSP FASB Interpretation (FIN) 39-1, issued April 2007, allows entities that are party to a master netting arrangement to offset the receivable or payable recognized upon payment or receipt of cash collateral against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement.  Upon adoption of FSP FIN 39-1, an entity is required to make an accounting policy decision to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements.  FSP FIN 39-1 is effective January 1, 2008.  The effect of initially applying FSP FIN 39-1 must be recognized retrospectively as a change in accounting principle, unless impracticable to do so.  We are evaluating the impact of FSP FIN 39-1 on our financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

· FAS 157, Fair Value Measurement, issued September 2006, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  FAS 157 clarifies that the exchange price is the price in the principal market in which the reporting entity would transact for the asset or liability.  We are required to disclose inputs used to develop fair value measurements and the effect of any of our assumptions on earnings or changes in net assets for the period.  The provisions of FAS 157 will become effective January 1, 2008.  We are evaluating the impact of FAS 157 on our financial statements, and will incorporate these additional disclosure requirements in our financial statements for the quarter ending March 31, 2008.

· FAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, issued February 2007, provides companies with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur.  FAS 159 also establishes disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elects the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each item.  The provisions of FAS 159 will become effective January 1, 2008.  We are evaluating the impact of FAS 159 on our financial statements, and will incorporate any additional disclosure requirements in our financial statements for the quarter ending March 31, 2008.

· In the third quarter of 2006, the Pension Protection Act of 2006 (Pension Act) was signed into law, which will be effective January 1, 2008.  The new law will affect the manner in which many companies, including UniSource Energy and TEP, administer their pension plans.  The Pension Act requires companies to increase the funding of their pension plans, increase premiums to the Pension Benefit Guaranty Corporation for defined benefit plans, amend plan documents and provide additional disclosures in regulatory filings and to plan participants.  We are currently assessing the impact the Pension Act may have on our financial statements.

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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,
	2007			2006
	-Thousands of Dollars-
Net Income	$	42,167		$	55,023
Adjustments to Reconcile Net Income
To Net Cash Flows
Depreciation and Amortization Expense		103,494			96,767
Depreciation Recorded to Fuel and Other O&M Expense		5,178			5,760
Amortization of Transition Recovery Asset		59,944			51,080
Mark-to-Market Transactions		1,525			(371	)
Net Unrealized Loss on MEG Trading Activities		1,165			3,056
Amortization of Deferred Debt-Related Costs included in Interest Expense		2,879			3,509
Loss on Extinguishment of Debt		-			1,080
Provision for Bad Debts		2,333			2,635
Deferred Income Taxes		24,830			13,328
Pension and Postretirement Expense		10,832			13,195
Pension and Postretirement Funding		(12,585	)		(11,753	)
Stock Based Compensation Expense		2,372			1,886
Excess Tax Benefit from Stock Option Exercises		(443	)		(1,106	)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(2,051	)		(26,821	)
Materials and Fuel Inventory		(9,310	)		(4,215	)
Over/Under Recovered Purchased Gas Cost		3,515			13,636
Accounts Payable		(23,968	)		(22,846	)
Interest Accrued		(14,271	)		(17,192	)
Income Tax Receivable/Payable		(17,025	)		(10,493	)
Accrued Taxes Other Than Income Taxes		13,670			12,514
Other		9,286			18,660
Discontinued Operations – Net of Tax		-			2,669
Net Cash Used by Operating Activities of Discontinued Operations		-			(2,710	)
Net Cash Flows – Operating Activities	$	203,537		$	197,291

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) – Unaudited

	TEP
	Nine Months Ended
	September 30,
	2007			2006
	-Thousands of Dollars-
Net Income	$	39,051		$	57,408
Adjustments to Reconcile Net Income
To Net Cash Flows
Depreciation and Amortization Expense		88,033			83,504
Depreciation Recorded to Fuel and Other O&M Expense		4,038			4,812
Amortization of Transition Recovery Asset		59,944			51,080
Mark-to-Market Transactions		1,525			(954	)
Amortization of Deferred Debt-Related Costs included in Interest		2,004			2,560
Pension and Postretirement Expense		9,512			11,942
Pension and Postretirement Funding		(11,430	)		(10,388	)
Stock Based Compensation Expense		1,847			1,489
Loss on Extinguishment of Debt		-			685
Provision for Bad Debts		1,197			1,373
Deferred Income Taxes		15,598			13,771
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(18,844	)		(47,913	)
Materials and Fuel Inventory		(9,596	)		(2,807	)
Accounts Payable		(8,506	)		(14,576	)
Interest Accrued		(9,846	)		(12,531	)
Income Tax Receivable/Payable		(12,022	)		(21,524	)
Accrued Taxes Other Than Income Taxes		13,717			12,139
Other		(3,078	)		13,431
Net Cash Flows – Operating Activities	$	163,144		$	143,501

NOTE 14.  REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The UniSource Energy and TEP condensed consolidated financial statements as of September 30, 2007 and for the three- and nine-month periods ended September 30, 2007 and 2006 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm.  Their reports (dated November 1, 2007) are included on pages 1 and 2.  The reports of PricewaterhouseCoopers LLP state that they did not audit and they do not express an opinion on that unaudited financial information.  Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied.  PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their reports on the unaudited financial information because neither of those reports is a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

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

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

· outlook and strategies,

· operating results during the third quarter and nine months ended September 30, 2007 compared with the same periods in 2006,

· factors which affect 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 UniSource Energy and TEP’s 2006 Annual Report on Form 10-K and with the Comparative Condensed Consolidated Financial Statements, beginning on page 3, which present the results of operations for the three and nine months ended September 30, 2007 and 2006.  Management’s Discussion and Analysis explains the differences between periods for specific line items of the Comparative Condensed Consolidated Financial Statements.

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

UNISOURCE ENERGY CONSOLIDATED

OVERVIEW OF CONSOLIDATED BUSINESS

UniSource Energy is a holding company that has no significant operations of its own.  Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities.  UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).  We conduct our business in three primary business segments – TEP, UNS Gas and UNS Electric.

TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years.  UES was established in 2003, when it acquired the Arizona gas and electric properties from Citizens.  UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in Northern and Southern Arizona.  These companies are regulated by the Arizona Corporation Commission (ACC).

Millennium has existing investments in unregulated businesses that represent 3% of UniSource Energy’s total assets as of September 30, 2007; no new investments are planned at Millennium.  UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that, subject to approval, is expected to provide energy to UNS Electric.

OUTLOOK AND STRATEGIES

Our financial prospects and outlook for the next few years will be affected by many competitive, regulatory and economic factors.  Our plans and strategies include the following:

· Efficiently manage our generation, transmission and distribution resources and seek ways to control our operating expenses while maintaining and enhancing reliability and profitability;

· Expand TEP’s portfolio of generating and purchased power resources, along with programs to expand renewable energy sources and demand side management,  to meet growing retail energy demand and respond to wholesale market opportunities;

· Expand UNS Electric’s portfolio of generating and purchased power resources to substitute for the May 2008 expiration of the full requirements contract with Pinnacle West Marketing and Trading (PWMT) and to meet growing retail energy demand;

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· Receive ACC approval of a rate increase for TEP, effective January 2009, that resolves the uncertainty surrounding TEP’s rates for generation service after 2008, while providing adequate revenues to cover the rising cost of serving its customers and preserving TEP’s benefits under the Settlement Agreement;

· Receive ACC approval of rate increases for UNS Gas and UNS Electric to provide adequate revenues to cover the rising cost of providing service to their customers;

· Enhance the value of existing generation assets by working with Salt River Project to support the construction of Springerville Unit 4;

· Enhance the value of TEP’s transmission system while continuing to provide reliable access to generation for TEP and UNS Electric’s retail customers and market access for all generating assets;

· Continue to develop synergies between UNS Gas, UNS Electric and TEP;

· Improve capital structure; and

· Promote economic development in our service territories.

To accomplish our goals, during 2007 we expect to spend the following amounts on capital expenditures:

	Actual Year-to-Date September 30, 2007	Estimate Full Year 2007
	-Millions of Dollars-
TEP	$123	$199
UNS Gas	18	33
UNS Electric	31	40
Other (1)	10	27
UniSource Energy Consolidated	$182	$299

⁽¹⁾ Represents capital expenditures by UED related to the construction of the 90 MW BMGS in Kingman, Arizona, in UNS Electric’s service area.  The project is expected to be completed in 2008.

RESULTS OF OPERATIONS

Executive Overview

Three Months Ended September 30

UniSource Energy recorded income from continuing operations of $25 million in the third quarter of 2007 compared with $28 million in the third quarter of 2006.  UniSource Energy’s third quarter 2007 net income was negatively impacted by higher fuel expenses and purchased power costs at TEP, as well as higher amortization of TEP’s Transition Recovery Asset (TRA).

Nine Months Ended September 30

UniSource Energy recorded income from continuing operations of $42 million in the first nine months of 2007 compared with $58 million in the same period last year.

The decrease in UniSource Energy’s net income in the first nine months of 2007 is due to costs at TEP associated with planned coal plant outages that occurred mainly during the first three months of the year, higher fuel and purchased power costs, mild weather during the second quarter and higher amortization of TEP’s TRA.  The scheduled maintenance outages put upward pressure on TEP’s operations and maintenance (O&M) costs and also limited wholesale sales opportunities.

On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar in the future. In the first quarter of 2006, UniSource Energy recorded an

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after-tax loss of approximately $3 million related to the discontinued operations and disposal of Global Solar. See Other Non-Reportable Segments, Results of Operations, Discontinued Operations – Global Solar, below.

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 net income (loss).

	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
	-Millions of Dollars-		-Millions of Dollars-
TEP	$26	$30	$39	$57
UNS Gas	(2)	(2)	1	2
UNS Electric	3	2	5	4
Other (1)	(2)	(2)	(3)	(5)
Consolidated Net Income from Continuing Operations	$25	$28	$42	$58
Discontinued Operations (2)	-	-	-	(3)
Consolidated Net Income	$25	$28	$42	$55

⁽¹⁾ Includes: UniSource Energy parent company expenses; UniSource Energy parent company interest expense (net of tax) on the UniSource Convertible Senior Notes and on the UniSource Credit Agreement; and income and losses from Millennium investments.

⁽²⁾ Relates to the discontinued operations and sale of Global Solar by Millennium on March 31, 2006.

LIQUIDITY AND CAPITAL RESOURCES

UniSource Energy Consolidated Cash Flows

Nine Months Ended September 30,	2007	2006
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$204	$197
Investing Activities	(153)	(168)
Financing Activities	(95)	(89)

UniSource Energy’s consolidated cash flows are provided primarily from 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.

We use our available cash primarily to:

· fund capital expenditures;

· pay dividends to shareholders; and

· reduce leverage.

The primary source of liquidity for UniSource Energy, the parent company, is dividends from its subsidiaries, primarily TEP.  Also, 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 on a stand-alone basis, for each of its segments.

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Balances  as of October 31, 2007	Cash and Cash Equivalents	Borrowings under Revolving Credit Facility	Amount Available under Revolving Credit Facility
	-Millions of Dollars-
UniSource Energy stand-alone	$    1	$  29	$  41
TEP	13	10	140
UNS Gas	16	-	34 (1)
UNS Electric	9	26	19 (1)
Other	24 (2)	NA	NA
Total	$  63

⁽¹⁾ Either UNS Gas or UNS Electric may borrow up to a maximum of $45 million, but the total combined amount borrowed cannot exceed $60 million.

⁽²⁾ Includes cash and cash equivalents at Millennium.

Executive Overview

Operating Activities

In the first nine months of 2007, net cash flows from operating activities were $6 million higher than the same period in 2006.  The increase is primarily due to higher retail kWh sales in TEP’s service territory and operating receipts received by TEP related to Springerville Unit 3.

Investing Activities

Net cash used for investing activities was $15 million lower in the first nine months of 2007 compared with the same period in 2006.  In the first nine months of 2006, TEP used $48 million to purchase lease equity related to Springerville Unit 1.  Also, UniSource Energy received $16 million in proceeds in the first nine months of 2006 related to the sale of Global Solar.  Capital expenditures were higher in the first nine months of 2007 due primarily to the construction of the Black Mountain Generating Station by UED, as well as overall utility system growth.

Financing Activities

Net cash flows used for financing activities were $6 million higher in the first nine months of 2007 compared with the same period in 2006, primarily due to higher scheduled payments on capital lease obligations by TEP and higher dividends paid by UniSource Energy to its shareholders.  There was a timing difference in UniSource Energy’s quarterly dividends paid to its shareholders; in the first nine months of 2006, two quarterly dividends were paid, compared with three quarterly dividends this year.

Liquidity Outlook

As a result of growing capital expenditures at UniSource Energy’s subsidiaries, the revolving credit facilities at UniSource Energy, TEP, UNS Gas and UNS Electric may be used on a more frequent basis.  Other funding sources to meet the capital requirements of the strong utility customer growth could include the issuance of long-term debt, as well as capital contributions from UniSource Energy to its subsidiaries.  The need for external funding sources is partially dependent on the outcome of rate-related proceedings at TEP, UNS Gas and UNS Electric.

For more information concerning liquidity and capital resources, see Tucson Electric Power Company, Liquidity and Capital Resources, below, UNS Gas, Liquidity and Capital Resources, UNS Electric, Liquidity and Capital Resources, and Other Non-Reportable Segments, Liquidity and Capital Resources, below.

Capital Expenditures

UniSource Energy is currently undertaking its annual process of evaluating its capital needs for growth and for maintenance of transmission, distribution and generation assets.  Based on initial estimates, UniSource Energy's consolidated capital expenditures for 2008-2011 are expected to be higher than previously reported in its 2006 Annual Report on Form 10-K.  This expected increase is the result of several factors including:  strong customer

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growth in UniSource Energy's utility service territories; higher material and construction costs; the need to increase transmission capacity in TEP's service territory; and generation needs for UNS Electric.

UniSource Energy Credit Agreement

The UniSource Credit Agreement consists of a $30 million amortizing term loan facility and a $70 million revolving credit facility and matures in 2011.  At September 30, 2007, there was $23 million outstanding under the term loan facility and $28 million outstanding under the revolving credit facility at a weighted average interest rate of 6.69%.

Convertible Senior Notes

UniSource Energy has outstanding $150 million of 4.50% Convertible Senior Notes due 2035.  Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of our Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances.  The closing price of UniSource Energy’s Common Stock was $31.72 on October 31, 2007.

Guarantees and Indemnities

In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis.  The most significant of these guarantees at September 30, 2007 were:

· UES’ guarantee of senior unsecured notes issued by UNS Gas ($100 million) and UNS Electric ($60 million);

· UES’ guarantee of the $60 million UNS Gas/UNS Electric Revolver;

· UniSource Energy’s guarantee of approximately $5 million in natural gas transportation and supply payments in addition to building lease payments for UNS Gas.

To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated balance sheets.

In addition, UniSource Energy and its subsidiaries have indemnified the purchasers of interests in certain investments from additional taxes due for years prior to the sale.  The terms of the indemnifications provide for no limitation on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations.  We have not made any payments under the terms of these indemnifications to date.

We believe that the likelihood that UniSource Energy or UES would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.

Contractual Obligations

There have been no significant changes in our contractual obligations or other commercial commitments from those reported in our 2006 Annual Report on Form 10-K, other than:

· Effective August 1, 2007, Tri-State Generation and Transmission Association (Tri-State) terminated its power sale agreement with TEP.  Under the agreement, Tri-State provided TEP with 100 MW of system capacity from September 1, 2006 until the termination of the agreement.

· In July 2007, TEP entered into a power supply agreement for the period June through September 2008.  This contract is indexed to natural gas prices.  TEP estimates its minimum payments under this contract to be $8 million based on natural gas prices as of September 30, 2007.

· In July 2007, TEP entered into an agreement to purchase 75,000 tons of coal from the McKinley Mine during the remainder of 2007.  TEP estimates the minimum payments under this contract to be $2 million in 2007.

· In June 2007, UNS Gas entered into a pipeline capacity contract for the period March 2008 through February 2020 with demand charges approximating $1 million annually.

· In May 2007, TEP entered into a pipeline capacity contract for the period May 2007 through April 2008.  TEP expects the reservation charges under this contract to approximate $3 million in 2007 and $1 million in 2008.

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· In 2006 and in 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric estimates its future minimum payments under these contracts to be $48 million in 2008, $59 million in 2009, $38 million in 2010, $15 million in 2011, $8 million in 2012, and $8 million thereafter based on natural gas prices as of September 30, 2007.

· In 2007, UNS Gas entered into forward gas purchases with future minimum payments approximating $6 million for the remainder of 2007, $17 million in 2008, $12 million in 2009, and $7 million in 2010.

· In March 2007, TEP entered into a one-year gas transportation agreement.  TEP expects the minimum payments under this contract to be less than $1 million in 2007 and less than $0.3 million in 2008.

· As a result of adopting FIN 48 on January 1, 2007, TEP estimates its net liability for uncertain tax positions is $7 million (reflecting a $13 million uncertain tax liability and a $6 million uncertain tax receivable).  TEP estimates its liability for uncertain tax positions will be settled in 2008 or thereafter.

· Under a settlement agreement signed in 2005 with the New Mexico Environmental Department and environmental activist groups, the co-owners of San Juan will install new technology at the generating station to reduce mercury, particulate matter, NO_x and SO₂ emissions.  TEP's share of the cost of new pollution control equipment based on its ownership of San Juan has increased from $65 million over the next three years to $11 million in 2007, $55 million in 2008 and $14 million in 2009 as a result of higher commodity prices, and construction and engineering costs.

Dividends on Common Stock

The following table shows the dividends declared to UniSource Energy shareholders for 2007:

Declaration Date	Record Date	Payment Date	Dividend Amount Per Share of Common Stock
February 9, 2007	February 20, 2007	March 14, 2007	$0.225
May 11, 2007	May 23, 2007	June 15, 2007	$0.225
September 4, 2007	September 17, 2007	September 28, 2007	$0.225

Income Tax Position

At September 30, 2007, UniSource Energy and TEP had, for federal and state income tax filing purposes: AMT Credit carryforward amounts of $56 million and $42 million, respectively; and a $26 million Capital Loss carryforward at UniSource Energy.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

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

Three Months Ended September 30

TEP recorded net income of $26 million in the third quarter of 2007 compared with $30 million in the same period last year.  The following factors contributed to the decrease:

· a $3 million decrease in total operating revenues less fuel and purchased power expense due to the following:

· an $18 million increase in retail revenues due to customer growth of 2% and a 27% increase in cooling degree days (CDD);

· a $7 million increase in other revenues due primarily to fees and reimbursements received from Tri-State for fuel and O&M costs related to Springerville Unit 3:

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· a $6 million increase in wholesale revenues due primarily to higher short-term wholesale sales activity; offset by

· a $22 million increase in purchased power expense due to higher short-term wholesale activity and an increase in purchase volumes to meet retail load;

· a $12 million increase in fuel expense due to an increase in gas-fired generation to meet higher retail demand and higher coal and rail expenses compared with the third quarter of 2006.  See Operating Expenses, Fuel and Purchased Power Expense, below.

Other factors impacting third quarter 2007 results include:

· a $1 million increase in O&M expense due primarily to expenses related to Springerville Unit 3 that TEP incurred as the operator of the plant and for which TEP received reimbursement from Tri-State and recorded in other operating revenue.  O&M expense in the third quarter of 2007 includes $6 million of expenses relate to Springerville 3 compared with $3 million last year.  O&M expense in the third quarters of 2007 and 2006 was partially offset by pre-tax gains of $3 million related to the sale of excess SO2 Emission Allowances;

· a $4 million increase in the amortization of TEP’s TRA.

· a $3 million decrease in total other income due primarily to lower income on reduced lease debt holdings and a $2 million increase in charitable contributions; and

· a $6 million decrease in total interest expense due to lower balances on capital lease obligations.  In addition, third quarter 2006 interest expense included a $2 million interest payment to the IRS for proposed adjustments to previously filed tax returns and the write-off of fees related to amending TEP’s credit agreement.

In the third quarters of 2007 and 2006, the net pre-tax benefit recognized by TEP related to Springerville Unit 3 for transmission revenues, operating fees, construction bonus and a reduction in its share of the common costs was $6 million and $3 million, respectively.

Nine Months Ended September 30

TEP recorded net income of $39 million in the first nine months of 2007 compared with $57 million in the same period last year.  The following factors contributed to the decrease:

· a $1 million decrease in total operating revenues less fuel and purchased power expense due to the following:

· a $31 million increase in retail revenues due to hot weather during the third quarter, cool weather during the first quarter and customer growth of 2%;

· a $10 million increase in wholesale revenues.   Wholesale revenues in the first nine months of 2007 and 2006 included $6 million and $1 million, respectively, of transmission revenues related to Springerville Unit 3.  Wholesale revenues also benefited from higher short-term wholesale sales activity;

· a $20 million increase in other revenues due primarily to fees and reimbursements received from Tri-State for fuel and O&M costs related to Springerville Unit 3; offset by:

· a $36 million increase in purchased power expense due to increased retail energy demand during the third quarter, higher short-term wholesale activity and expenses related to the 100 MW purchased power contract with Tri-State that commenced in September 2006 and ended August 1, 2007; and

· a $26 million increase in fuel expense due to an increase in gas-fired generating output, as well as increases in coal and rail expenses.  See Operating Expenses, Fuel and Purchased Power Expense, below.

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Other factors impacting the results of the first nine months of 2007 include:

· a $20 million increase in O&M expense due in part to planned maintenance outages at San Juan Unit 2 and Springerville Unit 2 during the first quarter of 2007.  Other factors contributing to higher O&M include operating expenses at Luna, and expenses related to Springerville Unit 3 that TEP incurred as the operator of the plant and for which TEP received reimbursement from Tri-State.  TEP’s O&M expense in the first nine months of 2007 included $15 million related to the operating of Springerville Unit 3, compared with $4 million in the same period last year.  O&M expense in the first nine months of 2007 was partially offset by a pre-tax gain of $10 million related to the sale of excess SO2 Emission Allowances, compared with a pre-tax gain of $7 million in the same period last year;

· a $9 million increase in the amortization of TEP’s Transition Recovery Asset (TRA);

· a $5 million increase in depreciation and amortization due primarily to additions to plant in service; and

· a $9 million decrease in total interest expense due to lower balances on capital lease obligations.  In addition, interest expense in the first nine months of 2006 included an interest payment to the IRS for proposed adjustments to previously filed tax returns and the write-off of fees related to the amendment of TEP’s credit agreement.

In the third quarters of 2007 and 2006, the net pre-tax benefit recognized by TEP related to Springerville Unit 3 for transmission revenues, operating fees, construction bonus and a reduction in its share of the common costs was $15 million and $3 million, respectively.

Utility Sales and Revenues

	Sales				Operating Revenue
Three Months Ended Sept. 30,	2007		2006		2007		2006
	-Millions of kWh-				-Millions of Dollars-
Electric Retail Sales:
Residential		1,436		1,297	$	135	$	122
Commercial		620		583		65		61
Industrial		671		657		49		49
Mining		244		236		12		11
Public Authorities		66		65		5		5
Total Electric Retail Sales		3,037		2,838	$	266	$	248
Electric Wholesale Sales Delivered:
Long-term Contracts		272		255		15		13
Other Sales		525		543		28		25
Transmission		-		-		4		3
Total Electric Wholesale Sales		797		798		47		41
Total Electric Sales		3,834		3,636	$	313	$	289
Weather Data:	2007		2006
Cooling Degree Days
Three Months Ended Sept. 30,		1,010		795
10-Year Average for Three Months    Ended Sept. 30,		942		943

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	Sales				Operating Revenue
Nine Months Ended Sept. 30,	2007		2006		2007		2006
	-Millions of kWh-				-Millions of Dollars-
Electric Retail Sales:
Residential		3,209		3,008	$	293	$	275
Commercial		1,575		1,498		164		156
Industrial		1,798		1,751		129		127
Mining		727		688		36		33
Public Authorities		188		195		14		14
Total Electric Retail Sales		7,497		7,140	$	636	$	605
Electric Wholesale Sales Delivered:
Long-term Contracts		812		792		42		39
Other Sales		1,645		1,651		86		84
Transmission		-		-		11		6
Total Electric Wholesale Sales		2,457		2,443		139		129
Total Electric Sales		9,954		9,583	$	775	$	734
Weather Data:	2007		2006
Cooling Degree Days
Nine Months Ended Sept. 30,		1,477		1,338
10-Year Average for Nine Months     Ended Sept. 30,		1,383		1,377

Mark-to-Market Adjustments on Trading Activity

The table below summarizes the net unrealized gains (losses) on TEP’s forward sales and purchases of energy.  The net unrealized gain (loss) on forward sales and purchases of energy is presented on the income statement in wholesale revenues.  Amounts for 2007 are based on the market price of energy as of September 30, 2007.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2007	2006	2007	2006
	-Millions of Dollars-
Gain (Loss) on Forward Power Sales & Purchases	$  -	$1	$  -	$1

Operating Expenses

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for the three months ended September 30, 2007 and 2006 are shown in the table below.

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	Generation and Purchased Power						Expense
Three Months Ended September 30,	2007			2006			2007		2006
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation
Four Corners		210			209		$	3	$	3
Navajo		331			352			6		5
San Juan		628			681			14		15
Springerville		1,584			1,569			26		26
Sundt Unit 4		197			191			7		5
Total Coal-Fired Generation		2,950			3,002			56		54
Gas-Fired Generation
Luna		236			175			15		9
Other Gas Units		175			152			18		14
Total Gas-Fired Generation		411			327			33		23
Solar and Other		1			2			-		-
Total Generation (1)		3,362			3,331			89		77
Total Purchased Power		818			614			58		36
Total Resources		4,180			3,945		$	147	$	113
Less Line Losses and Company Use		(346	)		(309	)
Total Energy Sold		3,834			3,636
(1) Fuel expense in the third quarters of 2007 and 2006 excludes $1 million related to Springerville Unit 3; these expenses are reimbursed by Tri-State and recorded in Other Revenue.

Coal-fired generation decreased by 2% compared with the third quarter of 2006, due to lower plant availability.  Despite lower coal-fired generating output, coal-related fuel expense was $2 million higher than the third quarter of 2006 due to higher coal and rail costs.  See Coal Supply, below.

Gas-fired generation increased by 84,000 MWh, and gas-related fuel expense was $10 million higher than the third quarter of 2006 primarily due to higher retail demand and lower coal plant availability.

Power purchases increased 33% compared with the third quarter of 2006, leading to a $22 million increase in purchased power expense.  The higher purchased power volume and expense is due primarily to higher retail demand and higher short-term wholesale sales activity.  In addition, during the third quarter of 2006, TEP purchased test power from Tri-State that was priced below market, prior to commercial operation of Springerville Unit 3.

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	Generation and Purchased Power						Expense
Nine Months Ended September 30,	2007			2006			2007		2006
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation
Four Corners		510			612		$	9	$	9
Navajo		948			931			16		13
San Juan		1,759			1,939			42		44
Springerville		4,388			4,297			73		71
Sundt Unit 4		558			470			18		11
Total Coal-Fired Generation		8,163			8,249			158		148
Gas-Fired Generation
Luna		586			400			35		18
Other Gas Units		255			278			27		25
Total Gas-Fired Generation		841			678			62		43
Solar and Other		6			7			-		-
Total Generation (1)		9,010			8,934			220		191
Purchased Power		1,772			1,411			115		79
Total Resources		10,782			10,345		$	335	$	270
Less Line Losses and Company Use		(828	)		(734	)
Total Energy Sold		9,954			9,611
(1) Fuel expense in the first nine months of 2007 and 2006 excludes $4 million and $7 million, respectively, related to Springerville 3; these expenses are reimbursed by Tri-State and recorded in Other Revenue.

Coal-fired generation decreased 1% compared with the first nine months of 2006, due primarily to several planned outages during the first three months of 2007.  As a result of the outages, TEP used Luna to help offset the amount of purchased power needed to replace the lost coal-fired capacity.  Despite lower output from TEP’s coal-fired generating units, total coal-related fuel expense was $10 million, or 7% higher than the same period last year, due primarily to higher coal and rail costs at Sundt Unit 4 and higher mining costs at San Juan and Navajo.  See Coal Supply, below.

Gas-fired generation increased by 24% and gas-related fuel expense was $19 million higher than the first nine months of 2006 due to the availability of Luna during 2007, lower coal-plant generating output and higher retail energy demand.

The lower availability of TEP’s coal plants in the first quarter of this year, higher retail energy demand, increased wholesale sales activity and energy purchased from Tri-State under a purchased power agreement contributed to an increase in power purchases of 361,000 MWh, or 26%, compared with the first nine months of last year.  Purchased power expense increased by $36 million as a result of the higher purchase volumes and demand charges associated with the Tri-State purchased power contract.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
	-cents per kWh-		-cents per kWh-
Coal	1.90	1.80	1.94	1.79
Gas*	8.03	7.12*	7.37	6.60*
All fuels	2.65	2.31	2.44	2.14
Purchased Power	7.09	5.86	6.49	5.60

* In 2006, the average cost of gas generation per kWh excludes test energy produced at

  Luna and its associated fuel costs.

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FACTORS AFFECTING RESULTS OF OPERATIONS

FERC Proceeding

TEP is a party to a proceeding pending at FERC involving the interpretation of the 1982 Power Exchange and Transmission Agreement (1982 Agreement) between TEP and El Paso Electric (El Paso).  The dispute relates to TEP’s ability to use existing rights for the transmission of power from Luna to TEP’s system.  On September 6, 2007, a FERC ALJ issued an initial decision, subject to full FERC review, that supports TEP’s position.   

As part of this proceeding, TEP has requested that FERC order El Paso to refund transmission charges paid by TEP during the pendency of this dispute proceeding. These refunds include $3.5 million paid in 2006, $2 million paid through September 2007, a projected $0.7 million for the fourth quarter of 2007, as well as any additional disputed transmission purchased until FERC issues its final order rule.  TEP expects FERC to issue its final order in 2008.

Retail Competition

In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP); however, only a small number of commercial and industrial customers initially chose an ESP.  By 2002, none of TEP’s retail customers were served by an alternative ESP.

In 2004, an Arizona Court of Appeals decision held invalid certain portions of the ACC rules on retail competition and related market pricing.  In February 2006, the ACC Staff requested that a proceeding be opened to address the issue of retail electric competition.  We cannot predict what changes, if any, the ACC will make to the competition rules.  TEP has met all conditions required by the ACC to facilitate electric retail competition, including ACC approval of TEP’s direct access tariffs.

TEP competes against gas service suppliers and others that provide energy services.  Other forms of energy technologies may provide competition to TEP’s services in the future, but to date, are generally not financially viable alternatives for its retail customers.  Self-generation by TEP’s large industrial customers could also provide competition for TEP’s services in the future, but has not had a significant impact to date.

In the wholesale market, TEP competes with other utilities, power marketers and independent power producers in the sale of electric capacity and energy.

TEP Rate Proposal Filing

Beginning in May 2005, TEP filed a series of pleadings requesting the ACC to resolve the uncertainty surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008.  TEP filed the pleadings in response to the Arizona Court of Appeals’ ruling related to retail competition and market pricing and a lack of agreement as to the interpretation of the Settlement Agreement by a number of participants in TEP’s rate proceedings.  TEP believes that the Settlement Agreement contemplated market based rates for generation service after 2008.  See Competition, above, for information regarding the 2004 court ruling.

In accordance with an ACC order in this proceeding, TEP filed three rate proposal methodologies with the ACC to establish new rates for TEP when the existing rate increase moratorium of the Settlement Agreement is lifted on January 1, 2009.  At this time, TEP cannot predict which, if any, of the proposed methodologies will be adopted by the ACC or when the ACC will issue its final order.

TEP has requested the rate proposal proceeding be concluded within 18 months in order for a rate increase to be effective no later than January 1, 2009.  In October 2007, the ALJ issued a procedural order establishing the following schedule for TEP’s rate case:

	Date
ACC Staff and intervenor testimony	February 22, 2008
TEP rebuttal testimony	March 25, 2008
ACC Staff and intervenor surrebuttal testimony	April 21, 2008
TEP rejoinder testimony	May 5, 2008
Hearings before ALJ	May 12, 2008

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As part of this proceeding, all of TEP’s legal rights and claims arising out of the Settlement Agreement and the decision approving the Settlement Agreement are fully preserved.

Market Methodology

This methodology would determine transmission and distribution rates using cost-of-service principles. Rates for generation service would be determined by using the market-based proxy, the Market Generation Credit (MGC), which was developed pursuant to the Settlement Agreement and approved by the ACC.

TEP’s rate base under this methodology would include an Implementation Cost Regulatory Asset (ICRA) of $14 million amortized over four years to reflect a portion of the costs of TEP’s transition to retail competition under the Settlement Agreement.  Under this methodology, transmission and ancillary service rates would reflect the rates in TEP’s FERC-approved Open Access Transmission Tariff (OATT) and TEP’s service area would remain open to direct access retail competition.

If adopted, it is projected that the Market Methodology would result in an overall increase of approximately 22% over current rates.

Cost-of-Service Methodology

This methodology would determine transmission, distribution and generation rates using cost-of-service principles.

TEP’s rate base under this methodology would include an ICRA of $47 million (including the $14 million described in the Market Methodology) amortized over four years to reflect the total costs of TEP’s transition to retail competition under the Settlement Agreement, in addition to a Termination Cost Regulatory Asset (TCRA) of $788 million to be recovered over 10 years for the economic burden shouldered by TEP under the Settlement Agreement, assuming TEP is not permitted to charge market rates for generation service beginning in 2009.

Under this methodology, a Purchased Power and Fuel Adjustor Clause (PPFAC) will be implemented.  In addition, Luna would be included in the PPFAC at $7 per KW-month for capacity plus the cost of fuel; Springerville Unit 1 would be included in base rates at its market value of $25.67 per kW-month; transmission and ancillary service rates would reflect TEP’s OATT rate; and the exclusivity of TEP’s Certificate of Convenience and Necessity would be restored.

If adopted, it is projected that the Cost-of-Service Methodology would result in an overall increase of approximately 23% over current rates.

Hybrid Methodology

This methodology would utilize a hybrid ratemaking approach whereby TEP’s transmission, distribution and generation rates would be established by cost-of-service principles in the Cost-of-Service Methodology described above including the PPFAC and $47 million ICRA, however certain generation assets would be excluded from cost-of-service ratemaking.  The Hybrid Methodology does not include the TCRA.

The excluded generation assets consist of TEP’s interest in Navajo Generating Station Units 1, 2 and 3  and its interest in Four Corners Generating Station Units 4 and 5 (the “Excluded Generation Assets”).  TEP’s share of the generating capacity at Navajo and Four Corners is approximately 278 MW. The Excluded Generation Assets would be dedicated to wholesale market transactions.

Under this methodology, transmission and ancillary service rates would reflect TEP’s OATT rate and TEP’s service area would be open to direct access retail competition for customers with at least 3 MW of load.

If adopted, it is projected that the Hybrid Methodology would result in an overall increase of approximately 15% over current rates.

Regulatory Assets

In the Cost-of-Service Methodology, the $788 million TCRA consists of foregone revenues under the rate freeze, along with carrying costs on the accumulated balance.  The foregone revenues are based on the annual retail

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revenue deficiency of $111 million for the test year ended December 31, 2003, identified by TEP in the 2004 rate review docket.  A separate charge of 1.26 cents/kWh represents the average retail rate TEP believes to be necessary to fully recover the TCRA over an estimated ten year time period.

In each of the three methodologies, TEP is seeking to include the ICRA in rate base to be amortized over four years.  The $14 million ICRA in the Market Methodology represents costs previously authorized by the ACC for deferral, while the $47 million ICRA in the Cost-of- Service and Hybrid Methodologies represents the total costs (excluding foregone revenues) incurred by TEP to transition to electric competition.

Purchased Power and Fuel Adjustment Clause

TEP does not currently have in place a PPFAC.  TEP is proposing a PPFAC that would reflect a forward-looking estimate of fuel and purchased power costs.  A PPFAC is included in both the Cost-of-Service and Hybrid Methodologies.

The PPFAC is proposed to be structured as follows:

Forward Component.  This component would be based on the difference between the forecasted fuel and purchased power costs for the following year and the amount recovered through base rates.  For example, forecasts for fuel and purchased power in 2010 would be used to establish the PPFAC Forward Component for 2010 as compared with the base cost of power included in rates.

True-Up Component. This component would reflect the difference between actual fuel and purchase power costs  with the amount TEP collected through both base rates and the PPFAC rate in a given year.  If actual costs were above (below) what was collected, the True-Up Component would be charged (credited) to the PPFAC rate for the subsequent year.

TEP’s proposal assumes the Base Cost of Fuel and Purchased Power for 2009 is based on forward market conditions for 2009, resulting in a PPFAC rate for 2009 of zero.  The PPFAC mechanism would be used to set the PPFAC for 2010 and subsequent years.

In the Cost-of-Service Methodology, TEP would credit 90% of short-term wholesale revenues against fuel and purchased power costs.  In the Hybrid Methodology, TEP would credit 100% of short-term wholesale revenues against these costs.

Rate Methodology Summary

The tables below summarize the major components for each of the rate methodologies, which are all based on a test year ending December 31, 2006.  All methodologies reflect a pro forma capital structure of 45% equity and 55% debt, as well as a 10.75% return on equity, a 6.39% cost of debt and an 8.35% weighted average cost of capital.

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	Market	Cost of Service	Hybrid
Rate increase over current rates	22%	23%	15%
Annual revenue increase	$172 million	$181 million	$117 million
Original cost rate base	$540 million	$983 million	$921 million
Fair value rate base*	$777 million	$1.42 billion	$1.31 billion
Rate base composition	Distribution and Local Generation assets	Distribution and Generation assets	Distribution and Generation assets (excluding Navajo and Four Corners)
TCRA	N/A	$788 million; not included in rate base	N/A
ICRA	$14 million included in rate base	$47 million included in rate base	$47 million included in rate base
PPFAC	N/A	Yes	Yes

*Fair value rate base as traditionally calculated by the ACC

Demand-Side Management Portfolio and Renewable Energy Standard and Tariff

In July 2007, TEP filed Demand-Side Management Portfolio and Renewable Energy Standard and Tariff (REST) plan information in separate dockets as ordered by the ACC.  TEP is requesting that appropriate cost recovery mechanisms be established in this rate proposal proceeding so that TEP may recover its costs associated with those programs in a timely manner.  TEP is also requesting that the cost recovery mechanisms be in place prior to the implementation of any plans.

Fixed Competition Transition Charge

According to a May 8, 2007 order of the ACC, TEP’s current Standard Offer rates shall  remain at their current level, including continued collection of the Fixed Competition Transition Charge (Fixed CTC) ($0.009 per kWh), until the effective date of a final order in the rate proposal proceeding.  The incremental revenue collected as a result of retaining the Fixed CTC after it would otherwise terminate shall accrue interest and shall be subject to refund or credit or other such mechanism to protect customers, as determined in the rate proposal docket.

The Fixed CTC would otherwise terminate when the TRA balance is amortized to zero (approximately May 2008).  From January 1, 2008 to approximately May 31, 2008, TEP expects to record Fixed CTC revenues of approximately $30 million and amortization expense of approximately $26 million related to the TRA.  After the expiration of the Fixed CTC, TEP does not expect to record any similar revenues or expense until or unless the ACC issues a final order that authorizes TEP to retain any incremental revenues.

TEP has proposed a full refund of these “true up” revenues over a 12-month period under the Market Methodology.  Under the Cost-of-Service and Hybrid Methodologies, TEP proposes other credits and offsets to be provided to customers in lieu of a refund.

Renewable Energy Standard and Tariff

In June 2007, the Arizona Attorney General certified the REST approved by the ACC in November 2006.  The REST rules require TEP and other affected utilities to generate or purchase at least 15% of their total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years starting with when the REST Implementation Plan and Tariff submitted by an affected utility is approved by the ACC.   The REST rules provide for recovery of above market costs a utility incurs in providing the renewable energy.

In October 2007, TEP filed a proposed REST Implementation Plan and Tariff with the ACC.  The filing contained two proposals: (1) a full compliance proposal that TEP estimates would require additional revenues of $24 million to meet the 2008 REST requirements; and (2) a proposal based on the ACC’s sample REST tariff that would require additional revenues of $12 million, but would not meet the residential portion of the 2008 REST

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requirements.  The REST Implementation Plan and Tariff are subject to ACC approval, which is expected to occur in early 2008.

Market Prices

The average market price for around-the-clock energy based on the Dow Jones Palo Verde Index was higher in the third quarter and first nine months of 2007 compared with the same periods last year, as well as the average price for natural gas based on the Permian Index for the same periods.  We cannot predict whether changes in various factors that influence demand and supply will cause prices to change for the remainder of 2007.

Average Market Price for Around-the-Clock Energy	$/MWh
Quarter ended September 30, 2007	$55
Quarter ended September 30, 2006	55
Nine months ended September 30, 2007	$53
Nine months ended September 30, 2006	50

Average Market Price for Natural Gas	$/MMBtu
Quarter ended September 30, 2007	$5.47
Quarter ended September 30, 2006	5.93
Nine months ended September 30, 2007	$6.13
Nine months ended September 30, 2006	6.21

In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers.  Some of these purchased power contracts are price indexed to natural gas prices.  Short-term and spot power purchase prices are also closely correlated to natural gas prices.  Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel and gas-indexed purchased power with fixed price contracts for a maximum of three years.  TEP had approximately 70% of this exposure hedged for October 2007 and has approximately 30% of this exposure hedged for April through October 2008.  TEP obtains its remaining gas fuel needs and purchased power in the spot and short-term markets.

The market price of energy may also affect TEP’s wholesale revenues.  TEP commits to future sales of energy as part of its ongoing efforts to hedge its excess generation based on projected generation capability, forward prices and generation costs.

In April 2007, TEP amended and restated its agreement to sell power to the Navajo Tribal Utility Authority (NTUA).  The terms of the new agreement began July 1, 2007 and include an extension of the expiration date from 2009 to the end of 2015.  The new agreement increases the cost of energy by approximately 10% to 15% to NTUA beginning July 1, 2007 and includes annual price escalators through 2015.  Starting in 2010, 50% of NTUA’s summer energy will be priced at spot market power indices.  During 2006, TEP sold approximately 250,000 MWh to NTUA.

We expect the market price and demand for capacity and energy to continue to be influenced by factors including:

· availability and price of natural gas;

· weather;

· continued population growth in the Western U.S.;

· economic conditions in the Western U.S.;

· availability of generating capacity throughout the Western U.S.;

· the extent of electric utility industry restructuring in Arizona, California and other Western states;

· FERC regulation of wholesale energy markets;

· availability of hydropower;

· transmission constraints; and

· environmental regulations and the cost of compliance.

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Coal Supply

For 2007, we expect TEP’s total coal-related fuel expense to increase by approximately $19 million, or 10%, due to: higher coal and transportation prices at Sundt Unit 4; increased mining costs at San Juan; higher expected generating output from TEP’s coal-fired plants; and cost increases at TEP’s other coal-fired plants.

In December 2006, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through 2008.  The price per ton of coal, including transportation, increased approximately 70%, compared with the costs under the terms of the prior agreement.  Based on these new agreements, and higher generating output, we expect coal-related fuel expense at Sundt Unit 4 to increase by $11 million in 2007.

Emission Allowances

TEP has SO₂ Emission Allowances in excess of what is required to operate its generating units.  The excess results primarily from a higher removal rate of SO₂ emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations.  From time to time, TEP will sell a portion of its excess SO₂ Emission Allowances.  The table below summarizes sales of SO₂ Emission Allowances made in 2006 and the first nine months of 2007, and forward sales as of September 30, 2007.

Delivery	Allowances Sold	Pre-tax Gain
2006		-Millions-
1st Quarter	2,500	$  2
2nd Quarter	2,500	2
3rd Quarter	5,000	3
Total 2006	10,000	$  7
2007
1st Quarter	2,500	$  2
2nd Quarter	7,500	5
3rd Quarter	5,000	3
4th Quarter	2,500	2
Total 2007	17,500	$12

In addition to the allowances contracted to be sold for the remainder of 2007, TEP expects to have approximately 18,000 excess SO₂ Emission Allowances available for sale through 2009.

LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows & Liquidity Outlook

During 2007, TEP expects to generate sufficient internal cash flows to fund most of its construction expenditures as well as operating activities, required debt maturities, and dividends to 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, as needed, its revolving credit facility to fund its business activities.  Furthermore, TEP may issue long-term debt or receive capital contributions from UniSource Energy to help fund its increasing capital expenditures.  The need for external funding beyond 2008 sources is partially dependent on the outcome of TEP’s rate proceedings.

The table below shows TEP’s net cash flows after capital expenditures, scheduled debt payments and payments on capital lease obligations which are paid at the beginning of January and July:

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Nine Months Ended September 30,	2007	2006
	-Millions of Dollars-
Net Cash Flows – Operating Activities (GAAP)	$  163	$ 144
Amounts from Statements of Cash Flows:
Less: Capital Expenditures	(123)	(111)
Net Cash Flows after Capital Expenditures (non-GAAP)*	40	33
Amounts from Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations	(71)	(61)
Plus:  Proceeds from Investment in Springerville      Lease Debt and Equity	28	22
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)*	$  (3)	$  (6)

Nine Months Ended September 30,	2007	2006
	-Millions of Dollars-
Net Cash Flows – Operating Activities (GAAP)	$ 163	$144
Net Cash Flows – Investing Activities (GAAP)	(97)	(138)
Net Cash Flows – Financing Activities (GAAP)	(75)	(45)
Net Cash Flows after Capital Expenditures (non-GAAP)	40	33
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)	(3)	(6)

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

Operating Activities

In the nine months of 2007, net cash flows from operating activities increased by $20 million compared with the same period in 2006.  Net cash flows were impacted by:

· a $71 million increase in cash receipts from electric retail and wholesale sales, offset by a $90 million increase in fuel and purchased energy costs.  TEP was negatively impacted by generating plant outages during the first quarter, as well as mild weather during the second quarter;

· a $26 million increase in cash receipts related to reimbursements received from Tri-State for the operation of Springerville Unit 3;

· a $3 million increase in proceeds from the sale of excess SO2 emission allowances;

· an $8 million decrease in total interest paid due to lower capital lease obligation balances;

· a $5 million increase in wages paid, part of which is related to payroll costs at Springerville Unit 3 that are reimbursed by Tri-State;

· a $35 million decrease in income taxes paid due to lower taxable income and payments made last year for amended tax returns; and

· a $21 million increase in O&M costs related to Springerville Unit 3 that are reimbursed by Tri-State as well as costs associated with plant outages.

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Investing Activities

Net cash used for investing activities was $41 million lower in the nine months of 2007 compared with the same period last year primarily due to the purchase of an interest in the lease equity of Springerville Unit 1 in 2006.

Financing Activities

Net cash used for financing activities was $30 million higher in the first nine months of 2007 compared with the same period in 2006.  The following factors contributed to the increase:

· a $19 million increase in net proceeds from borrowings under the TEP Revolving Credit Facility; and

· a $10 million increase in scheduled payments made on capital lease obligations.

Capital Lease Obligations

At September 30, 2007, TEP had $587 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.

Leased Asset	Capital Lease Obligation Balance at September 30, 2007	Expiration
	- In Millions -
Springerville Unit 1	$346	2015
Springerville Coal Handling Facilities	99	2015
Springerville Common Facilities	105	2020
Sundt Unit 4	36	2011
Other Leases	1	2008
Total Capital Lease Obligations	$587

Except for TEP’s 14% equity ownership in the Springerville Unit 1 Leases and its 13% equity ownership in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases.  TEP will either renew the leases or purchase the leased assets at such time.  The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time, while the purchase price option is fixed for the Springerville Coal Handing Facilities and Springerville Common Facilities.

Investments in Springerville Lease Debt and Equity

At September 30, 2007, TEP had $153 million of investments in lease debt and equity on its balance sheet.  TEP's investment in lease debt has been reduced by scheduled payments on capital lease obligations.  The yields on TEP’s investments in Springerville lease debt, at the date of purchase, range from 8.9% to 12.7%.  The table below provides a summary of the investment balances in lease debt.

	Lease Debt Investment Balance
Leased Asset	September 30, 2007	December 31, 2006
	- In Millions -
Investments in Lease Debt:
Springerville Unit 1	$  71	$  81
Springerville Coal Handling Facilities	34	52
Total Investment in Lease Debt	$105	$133

TEP Credit Agreement

The TEP Credit Agreement consists of a $150 million revolving credit facility and a $341 million letter of credit facility which supports $329 million of tax-exempt variable rate bonds.  The TEP Credit Agreement matures in 2011 and is secured by $491 million of 1992 Mortgage Bonds.  At September 30, 2007, there was $16 million outstanding under the revolving credit facility at a weighted average interest rate of 6.79%.

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Income Tax Position

See UniSource Energy, 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 2006 Annual Report on Form 10-K, other than:

· Effective August 1, 2007, Tri-State Generation and Transmission Association (Tri-State) terminated its power sale agreement with TEP.  Under the agreement, Tri-State provided TEP with 100 MW of system capacity from September 1, 2006 until the termination of the agreement.

· In July 2007, TEP entered into a power supply agreement for the period June through September 2008.  This contract is indexed to natural gas prices.  TEP estimates its minimum payments under this contract to be $8 million based on natural gas prices as of September 30, 2007.

· In July 2007, TEP entered into an agreement to purchase 75,000 tons of coal from the McKinley Mine during the remainder of 2007.  TEP estimates the minimum payments under this contract to be $2 million in 2007.

· In May 2007, TEP entered into a pipeline capacity contract for the period May 2007 through April 2008.  TEP expects the reservation charges under this contract to approximate $3 million in 2007 and $1 million in 2008.

· In March 2007, TEP entered into a one-year gas transportation agreement.  TEP expects the minimum payments under this contract to be less than $1 million in 2007 and less than $0.3 million in 2008.

· As a result of adopting FIN 48 on January 1, 2007, TEP estimates its net liability for uncertain tax positions is $7 million (reflects a $13 million uncertain tax liability and a $6 million uncertain tax receivable).  TEP estimates its liability for uncertain tax positions will be settled in 2008 or thereafter.

· Under a settlement agreement signed in 2005 with the New Mexico Environmental Department and environmental activist groups, the co-owners of San Juan will install new technology at the generating station to reduce mercury, particulate matter, NO_x and SO₂ emissions.  TEP's share of the cost of new pollution control equipment based on its ownership of San Juan has increased from $65 million over the next three years to $11 million in 2007, $55 million in 2008 and $14 million in 2009 as a result of higher commodity prices, and construction and engineering costs.

Dividends on Common Stock

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

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants.  As of September 30, 2007, TEP was in compliance with the terms of the TEP Credit Agreement and such financial covenants.

UNS GAS

RESULTS OF OPERATIONS

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UNS Gas reported a net loss of $2 million in the third quarters of 2007 and 2006.

As of September 30, 2007, UNS Gas’ customer base increased approximately 2% compared with last year.  The table below shows UNS Gas’ therm sales and revenues for the second quarters of 2007 and 2006.

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	Sales		Revenue
Three Months Ended September 30,	2007	2006	2007	2006
	- Millions of Therms -		- Millions of Dollars -
Retail Therm Sales:
Residential	5	6	$    9	$ 10
Commercial	4	4	4	6
Industrial	-	1	-	1
Public Authorities	1	-	1	1
Total Retail Therm Sales	10	11	14	18
Transport	-	-	-	1
Negotiated Sales Program (NSP)	3	3	2	2
Total Therm Sales	13	14	$ 16	$ 21

Retail therm sales were 9% lower in the third quarter of 2007 compared with the same period last year due to mild weather.  Retail revenues were 22% lower compared with the same period last year due primarily to a lower PGA surcharge.   See Factors Affecting Results of Operations, Rates and Regulation, Purchased Gas Adjustment Mechanism, below.

Through a Negotiated Sales Program (NSP) approved by the ACC, customers who receive gas transmission services from UNS Gas may also elect to purchase gas from UNS Gas.  Approximately one half of the margin earned on these NSP sales is retained by UNS Gas, while the remainder benefits retail customers through a credit to the PGA mechanism which reduces the gas commodity price.  See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.

The table below provides summary financial information for UNS Gas.

Three Months Ended September 30,	2007	2006
	- Millions of Dollars -
Gas Revenues	$ 16	$  21
Other Revenues	1	-
Total Operating Revenues	17	21
Purchased Gas Expense	10	14
Other Operations and Maintenance Expense	6	6
Depreciation and Amortization	2	1
Taxes other than Income Taxes	1	1
Total Other Operating Expenses	19	22
Operating Income (Loss)	(2)	(1)
Other Income	-	-
Total Interest Expense	2	2
Income Tax Expense (Benefit)	(2)	(1)
Net (Loss)	$  (2)	$   (2)

Nine Months Ended September 30, 2007 Compared with the Nine Months Ended September 30, 2006

UNS Gas reported net income of $1 million in the first nine months of 2007 and $2 million in the same period last year.

The table below shows UNS Gas’ therm sales and revenues for the nine months ending September 30, 2007 and 2006.

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	Sales		Revenue
Nine Months Ended September 30,	2007	2006	2007	2006
	- Millions of Therms -		- Millions of Dollars -
Retail Therm Sales:
Residential	48	45	$   62	$   65
Commercial	21	20	23	26
Industrial	1	2	1	2
Public Authorities	4	5	5	5
Total Retail Therm Sales	74	72	91	98
Transport	-	-	2	2
Negotiated Sales Program (NSP)	13	13	8	9
Total Therm Sales	87	85	$ 101	$ 109

Retail therm sales were 3% higher in the first nine months of 2007 compared with the same period last year, due primarily to customer growth and cold weather during the first quarter.  Despite similar retail therm sales, retail revenues were lower compared with the same period last year due to a lower PGA surcharge.  See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.

The table below provides summary financial information for UNS Gas.

Nine Months Ended September 30,	2007	2006
	- Millions of Dollars -
Gas Revenues	$ 101	$ 109
Other Revenues	2	2
Total Operating Revenues	103	111
Purchased Gas Expense	69	78
Other Operations and Maintenance Expense	20	18
Depreciation and Amortization	6	5
Taxes other than Income Taxes	2	2
Total Other Operating Expenses	97	103
Operating Income	6	8
Other Income	1	-
Total Interest Expense	5	5
Income Tax Expense (Benefit)	1	1
Net Income	$    1	$    2

FACTORS AFFECTING RESULTS OF OPERATIONS

RATES AND REGULATION

Energy Cost Adjustment Mechanism

UNS Gas’ retail rates include a PGA mechanism intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor.  The difference between UNS Gas’ actual gas and transportation costs and the cost of gas and transportation recovered through base rates are deferred and recovered or repaid through the PGA mechanism.

The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit.  The PGA factor is a mechanism that compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month period.  The actual gas and transportation costs that are either under or over collected through the base rate of $0.40 per therm or $4.00 per MMBtu and the PGA factor are charged or credited to a balancing account (PGA bank).  In the nine months ended September 30, 2007, the average PGA factor was approximately $0.383 per therm or $3.83 per MMBtu.

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The current annual cap on the maximum increase in the PGA factor is $0.10 per therm in a twelve month period.  In January 2006, UNS Gas filed a request with the ACC to increase the cap to allow for more timely recovery of actual gas costs.  In July 2006, UNS Gas requested this application be consolidated with its general rate case proceeding.  See General Rate Case Filing, below.

When the ACC-designated under or over recovery trigger points of $6.2 million and $4.5 million, respectively, are met on a billed to customers basis, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a period deemed appropriate by the ACC.   On September 30, 2007, the PGA bank balance was over-collected by $14 million on an accrual (GAAP) basis ($11 million on a billed to customers basis).

In September 2007, the ACC approved a 4 cent per therm PGA credit, effective October 2007 through April 2008.  Changes in the market price for gas, sales volumes and surcharge amount could significantly change the PGA bank balance in the future.

General Rate Case Filing

UNS Gas’ current rates have been in place since August 2003 and were designed to provide a 9.05% return on an original cost rate base of $118 million.  As a result of increased growth in UNS Gas’ service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Gas to recover its costs and earn a reasonable rate of return on its investment.  In July 2006, UNS Gas filed a general rate case.  Below is a table that summarizes UNS Gas’ request and the ALJ recommendation that was issued in October 2007:

Test year – December 31, 2005	Requested by UNS Gas	ALJ Recommendation
Original cost rate base	$162 million	$154 million
Revenue deficiency	$9 million	$5 million
Total rate increase (over test year revenues)	7%	4%
Cost of debt	6.60%	6.60%
Cost of equity	11.00%	10.00%
Hypothetical capital structure	50% equity / 50% debt	50% equity / 50% debt
Weighted average cost of capital	8.80%	8.30%

UNS Gas also requested modifications to its PGA mechanism to help address customer pricing issues posed by volatile gas prices, customer pricing that is inconsistent with the actual cost of gas, and the potential for over- or under-collections to result in the accumulation of large PGA bank balances.

The ALJ recommended the new rates go into effect on December 1, 2007. UNS Gas cannot predict the outcome of the rate case.  The ACC is scheduled to consider the UNS Gas rate case in an open meeting on November 8, 2007.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

In the first nine months of 2007, UNS Gas’ capital expenditures were $18 million.  UNS Gas expects internal cash flows to fund its future operating activities and a large portion of its construction expenditures. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements.  Sources of funding future capital expenditures could include draws on the revolving credit facility, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy. The need for external funding sources is partially dependent on the outcome of UNS Gas’ general rate case that was filed in July 2006.

The table below provides summary information for operating cash flow and capital expenditures for the first nine months of 2007 and 2006.

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Nine Months Ended September 30,	2007	2006
	- Millions of Dollars -
Net Cash Flows – Operating Activities	$19	$26
Capital Expenditures	18	19

UNS Gas/UNS Electric Revolver

In August 2006, UNS Gas and UNS Electric amended and restated their existing unsecured revolving credit agreement (UNS Gas/UNS Electric Revolver).  The amendment reduced the interest rate payable on borrowings, increased the amount of the revolving credit facility to $60 million from $40 million, and extended the maturity from April 2008 to August 2011.  Either borrower may borrow up to a maximum of $45 million, so long as the combined amount borrowed does not exceed $60 million.  The ACC approved the increase in the amount and term of the UNS Gas/UNS Electric Revolver in March 2007.

UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of its capital expenditures. As of September 30, 2007, UNS Gas had no outstanding borrowings under the UNS Gas/UNS Electric Revolver.

Senior Unsecured Notes

UNS Gas has $100 million of senior unsecured notes that are guaranteed by UES. The note purchase agreement for UNS Gas restricts transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness, and also contains a minimum net worth test.  As of September 30, 2007, UNS Gas was in compliance with the terms of its note purchase agreement.

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 $7 million in short-term debt.

Contractual Obligations

· In June 2007, UNS Gas entered into a pipeline capacity contract for the period March 2008 through February 2020 with demand charges approximating $1 million annually.

· In 2007, UNS Gas entered into forward gas purchases with future minimum payments approximating $6 million for the remainder of 2007, $17 million in 2008, $12 million in 2009, and $7 million in 2010.

Dividends on Common Stock

The note purchase agreement for UNS Gas contains restrictions on dividends.  UNS Gas may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test.  See Senior Unsecured Notes, above.  It is unlikely, however, that UNS Gas will pay dividends in the next few years due to expected cash requirements for capital expenditures.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $3 million in the third quarter of 2007 and $2 million in the third quarter of 2006.

Similar to TEP’s operations, we expect UNS Electric’s operations to be seasonal in nature, with peak energy demand occurring in the summer months.

As of September 30, 2007, UNS Electric’s customer base increased approximately 2% compared with last year.  The table below shows UNS Electric’s kWh sales and revenues for the third quarters of 2007 and 2006.

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	Sales		Revenue
Three Months Ended September 30,	2007	2006	2007		2006
	- Millions of kWh -		- Millions of Dollars -
Electric Retail Sales:
Residential	314	293	$  31	$  29
Commercial	187	178	19	17
Industrial	54	50	4	4
Other	-	1	-	-
Total Electric Retail Sales	555	522	$  54	$  50

Retail kWh sales were 6% higher in the third quarter of 2007 compared with the same period last year due to warmer weather and customer growth.

The table below provides summary financial information for UNS Electric.

Three Months Ended September 30,	2007	2006
	- Millions of Dollars -
Electric Revenues	$  54	$  50
Other Revenues	1	1
Total Operating Revenues	55	51
Purchased Energy Expense	37	35
Other Operations and Maintenance Expense	8	7
Depreciation and Amortization	3	3
Taxes other than Income Taxes	1	1
Total Other Operating Expenses	49	46
Operating Income	6	5
Other Income	-	-
Total Interest Expense	1	1
Income Tax Expense	2	2
Net Income	$  3	$   2

Nine Months Ended September 30, 2007 Compared with the Nine Months Ended September 30, 2006

UNS Electric reported net income of $5 million in the first nine months of 2007 and $4 million in the same period last year.  Results in the first nine months of 2007 include a pre-tax gain of $1 million related to the sale of land.

The table below shows UNS Electric’s kWh sales and revenues for the first nine months of 2007 and 2006.

	Sales		Revenue
Nine Months Ended September 30,	2007	2006	2007		2006
	- Millions of kWh -		- Millions of Dollars -
Electric Retail Sales:
Residential	693	650	$  69	$  65
Commercial	482	472	49	47
Industrial	149	145	12	11
Other	2	2	-	-
Total Electric Retail Sales	1,326	1,269	$ 130	$123

Retail kWh sales were 4% higher in the first nine months of 2007 compared with the same period last year due to customer growth.

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The table below provides summary financial information for UNS Electric.

Nine Months Ended September 30,	2007	2006
	- Millions of Dollars -
Electric Revenues	$  130	$ 123
Other Revenues	1	2
Total Operating Revenues	131	125
Purchased Energy Expense	87	84
Other Operations and Maintenance Expense	21	19
Depreciation and Amortization	10	8
Taxes other than Income Taxes	3	3
Total Other Operating Expenses	121	114
Operating Income	10	11
Other Income	2	-
Total Interest Expense	4	4
Income Tax Expense	3	3
Net Income	$  5	$    4

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

As required by the ACC order approving UniSource Energy’s acquisition of the Citizens’ Arizona gas and electric assets, in 2003 UNS Electric filed with the ACC a plan to open its service territories to retail competition by December 31, 2003.  The plan addressed all aspects of implementation.  It included UNS Electric’s unbundled distribution tariffs for both standard offer customers and customers that choose competitive retail access, as well as Direct Access and Settlement Fee schedules.  UNS Electric’s direct access rates for both transmission and ancillary services would be based upon its FERC Open Access Transmission Tariff.  The plan is subject to review and approval by the ACC, which has not yet considered the plan.  As a result of the court decisions concerning the ACC’s Rules, we are unable to predict when and how the ACC will address this plan.  See Tucson Electric Power Company, Factors Affecting Results of Operations, Competition, above for information regarding the Arizona Court of Appeals decision in 2004.

Rates and Regulation

Energy Cost Adjustment Mechanism

UNS Electric’s retail rates include a PPFAC, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under or over recovery of costs.  The ACC has approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWMT.

General Rate Case Filing

UNS Electric’s retail rates were last adjusted in August 2003.  As a result of increased growth in UNS Electric’s service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Electric to recover its costs and earn a reasonable rate of return on its investment.  In December 2006, UNS Electric filed a general rate case.  Below is a table that summarizes UNS Electric’s request:

Test year	12 months ended June 30, 2006
Original cost rate base	$141 million
Revenue deficiency	$8.5 million
Total rate increase (over test year revenues)	5.5%
Cost of long-term debt	8.2%
Cost of equity	11.8%
Actual capital structure	49% equity / 51% debt
Weighted average cost of capital	9.9%

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UNS Electric also requested the ACC to approve the acquisition of the 90 MW BMGS combustion turbine project under development by UED and to include the cost of the project in rate base effective June 1, 2008.   The cost of BMGS is expected to be $60 million to $65 million.

In June 2007, ACC Staff filed testimony that indicated a revenue deficiency for UNS Electric of approximately $4 million; RUCO’s testimony indicated a revenue deficiency of approximately $1 million.  Neither ACC Staff nor RUCO supported UNS Electric’s rate base proposal for BMGS.

UNS Electric also requested that a new PPFAC mechanism take effect when the current power supply agreement with PWMT expires in May 2008.

UNS Electric’s rate case hearings before the ALJ concluded in October 2007.  UNS Electric expects the ACC to rule on its rate case in early 2008.

Renewable Energy Standard and Tariff

In June 2007, the Arizona Attorney General certified the REST approved by the ACC in November 2006.  The REST rules require UNS Electric and other affected utilities to generate or purchase at least 15% of their total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years starting with when the REST Implementation Plan and Tariff submitted by an affected utility is approved by the ACC.   The REST rules provide for recovery of above market costs a utility incurs in providing the renewable energy.

In October 2007, UNS Electric filed a proposed REST Implementation Plan and Tariff with the ACC.  The filing contained two proposals: (1) a full compliance proposal that UNS Electric estimates would require additional revenues of $4 million to meet the 2008 REST requirements; and (2) a proposal based on the ACC’s sample REST tariff that would require additional revenues of $2 million, but would not meet the residential portion of the 2008 REST requirements.  The REST Implementation Plan and Tariff are subject to ACC approval, which is expected to occur in early 2008.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

In the first nine months of 2007, UNS Electric’s capital expenditures were $31 million.  UNS Electric expects internal cash flows to fund a portion of its construction expenditures.  Additional sources of funding future capital expenditures could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy. In April 2007, UniSource Energy contributed $10 million of capital to UNS Electric.  The need for external funding sources is partially dependent on the outcome of UNS Electric’s general rate case that was filed in December 2006.

The table below provides summary information for operating cash flow and capital expenditures for the first nine months of 2007 and 2006.

Nine Months Ended September 30,	2007	2006
	- Millions of Dollars -
Net Cash Flows – Operating Activities	$19	$ 9
Capital Expenditures	31	29

UNS Gas/UNS Electric Revolver

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

UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of its capital expenditures.  As of September 30, 2007, UNS Electric had $26 million outstanding under the UNS Gas/UNS Electric Revolver at a weighted average interest rate of 6.22%.

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Senior Unsecured Notes

UNS Electric has $60 million of 7.61% senior unsecured notes outstanding due in 2008 that 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, incurrence of indebtedness, and minimum net worth.  As of September 30, 2007, 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.

Contractual Obligations

In 2006 and in 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric estimates its future minimum payments under these contracts to be $48 million in 2008, $59 million in 2009, $38 million in 2010, $15 million in 2011, $8 million in 2012, and $8 million thereafter based on natural gas prices as of September 30, 2007.

Dividends on Common Stock

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.  See Senior Unsecured Notes, above.  It is unlikely, however, that UNS Electric will pay dividends in the next few years due to expected cash requirements for capital expenditures.

OTHER NON-REPORTABLE BUSINESS SEGMENTS

RESULTS OF OPERATIONS

The table below summarizes the income (loss) for the Other non-reportable segments.

Three Months Ended September 30,	2007	2006
	- Millions of Dollars -
Millennium Investments	$    -	$   -
UniSource Energy Parent Company	(1)	(2)
Total Other	$   (1)	$ (2)

Nine Months Ended September 30,	2007	2006
	- Millions of Dollars -
Millennium Investments	$    1	$   -
UniSource Energy Parent Company	(3)	(5)
Total Other	$   (2)	$ (5)

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.

UED

On-site construction of the 90 MW BMGS in Kingman, Arizona began during the third quarter of 2007 with an estimated completion date of May 2008, and pending ACC approval, is expected to provide energy to UNS Electric.  UED is financing the BMGS project with borrowings from UniSource Energy under an inter-company note payable.  At September 30, 2007, there was $31 million outstanding and interest is payable quarterly at LIBOR plus 1.25%.  The cost of BMGS is expected to be $60 million to $65 million.

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Discontinued Operations – Global Solar

On March 31, 2006, Millennium completed the sale of its interest in Global Solar.  In the first quarter of 2006, UniSource Energy recorded an after-tax loss of approximately $3 million related to the discontinued operations and disposal of Global Solar.

FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

MEG is in the process of winding down its activities and does not expect to engage in any significant new activities.  As of September 30, 2007, the fair value of MEG’s trading assets was $11 million and the fair value of MEG’s trading liabilities was $5 million.

Nations Energy Corporation (Nations Energy), a wholly-owned subsidiary of Millennium, has been inactive since 2001.  As of September 30, 2007, Nations Energy had a deferred tax asset of $3 million related to investment losses that has not been reflected on UniSource Energy’s consolidated income tax return.

Millennium is in the process of exiting its remaining investments.  At September 30, 2007, the book value of Millennium’s investments was $28 million.

LIQUIDITY AND CAPITAL RESOURCES

Millennium made a $5 million dividend payment to UniSource Energy in February 2007 and a $10 million dividend payment to UniSource Energy in April 2007.

UniSource Energy has ceased making loans or equity contributions to Millennium.  We anticipate that the funding required to finance Millennium’s remaining commitments will be provided only out of existing Millennium cash or cash returns from Millennium investments.  We believe such cash and returns will be adequate to fund Millennium’s remaining commitments.

CRITICAL ACCOUNTING ESTIMATES

In preparing financial statements under Generally Accepted Accounting Principles (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions.   UniSource Energy and TEP’s Critical Accounting Estimates are described in our Form 10-K for the year ended December 31, 2006 and include the following:

· Accounting for Rate Regulation

· Accounting for Asset Retirement Obligations

· Pension and Other Postretirement Benefit Plan Assumptions

· Accounting for Derivative Instruments, Trading Activities and Hedging Activities

· Unbilled Revenue – TEP, UNS Gas and UNS Electric

· Plant Asset Depreciable Lives – TEP, UNS Gas and UNS Electric

· Deferred Tax Valuation

Each of our critical accounting estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact the financial statements.  There have been no significant changes in our accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2006.

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NEW ACCOUNTING PRONOUNCEMENTS

The FASB recently issued the following Statements of Financial Accounting Standards (FAS):

· FSP FASB Interpretation (FIN) 39-1, issued April 2007, allows entities that are party to a master netting arrangement to offset the receivable or payable recognized upon payment or receipt of cash collateral against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FASB Interpretation 39.  Upon adoption of FSP FIN 39-1, an entity is required to make an accounting policy decision to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements.  FSP FIN 39-1 is effective January 1, 2008.  The effect of initially applying FSP FIN 39-1 must be recognized retrospectively as a change in accounting principle, unless impracticable to do so.  We are evaluating the impact of FSP FIN 39-1 on our financial statements.

· FAS 157, Fair Value Measurement, issued September 2006, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  FAS 157 clarifies that the exchange price is the price in the principal market in which the reporting entity would transact for the asset or liability.  We are required to disclose inputs used to develop fair value measurements and the effect of any of our assumptions on earnings or changes in net assets for the period.  FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  We are evaluating the impact of FAS 157 on our financial statements, and will incorporate these additional disclosure requirements in our financial statements for the quarter ending March 31, 2008.

· FAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, issued February 2007, provides companies with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur.  FAS 159 also establishes disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item.  The provisions of FAS 159 will become effective January 1, 2008.  We are evaluating the impact of FAS 159 on our financial statements, and will incorporate these additional disclosure requirements in our financial statements for the quarter ending March 31, 2008.

· In the third quarter of 2006, the Pension Protection Act of 2006 was signed into law, which will be effective January 1, 2008.  The new law will affect the manner in which many companies, including UniSource Energy and TEP, administer their pension plans.  The legislation will require companies to increase the amount by which they fund their pension plans, increase premiums to the Pension Benefit Guaranty Corporation for defined benefit plans, amend plan documents and provide additional disclosures in regulatory filings and to plan participants.  We are currently assessing the impact this law may have on our financial statements.

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 in the forward-looking statements.  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

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following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements.  These may be in addition to other factors and matters discussed in other parts of this report:

1. Supply and demand conditions in wholesale energy markets, including volatility in market prices and illiquidity in markets, are affected by a variety of factors, which include the availability of generating capacity in the Western U.S., including hydroelectric resources, weather, natural gas prices, the extent of utility restructuring in various states, transmission constraints, environmental regulations and cost of compliance, FERC regulation of wholesale energy markets, and economic conditions in the Western U.S.

2. Effects of competition in retail and wholesale energy markets.

3. Changes in economic conditions, demographic patterns and weather conditions in our retail service areas.

4. Effects of restructuring initiatives in the electric industry and other energy-related industries.

5. The creditworthiness of the entities with which we transact business or have transacted business.

6. Changes affecting our cost of providing electric and gas service including changes in fuel costs, generating unit operating performance, scheduled and unscheduled plant outages, interest rates, tax laws, environmental laws, and the general rate of inflation.

7. Changes in governmental policies and regulatory actions with respect to financing and rate structures.

8. The resolution of pending rate case proceedings and the resulting rate structures.

9. Changes affecting the cost of competing energy alternatives, including changes in available generating technologies and changes in the cost of natural gas.

10. Changes in accounting principles or the application of such principles to our businesses.

11. Changes in the depreciable lives of our assets.

12. Unanticipated changes in future liabilities relating to employee benefit plans due to changes in market values of retirement plan assets and health care costs.

13. The outcome of any ongoing or future litigation.

14. Ability to obtain financing through debt and/or equity issuance, which can be affected by various factors, including interest rate fluctuations and capital market conditions.

ITEM 3. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in this Item updates, and should be read in conjunction with, information included in Part II, Item 7A in UniSource Energy and TEP’s Annual Report on Form 10-K for the year ended December 31, 2006, in addition to the interim condensed consolidated financial statements and accompanying notes presented in Items 1 and 2 of this Form 10-Q.

We are exposed to various forms of market risk.  Changes in interest rates, returns on marketable securities, and changes in commodity prices may affect our future financial results.  The market risks resulting from changes in interest rates and returns on marketable securities have not changed materially from the market risks reported in our Annual Report on Form 10-K for the year ended December 31, 2006.  For additional information concerning risk factors, including market risks, see Safe Harbor for Forward-Looking Statements, above.

Risk Management Committee

We have a Risk Management Committee responsible for the oversight of commodity price risk and credit risk related to the wholesale energy marketing activities of TEP, the emissions and trading activities of MEG, and the fuel and power procurement activities at TEP, UNS Gas and UNS Electric.  Our Risk Management Committee,

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which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, transmission and distribution operations, and the generation operations departments of UniSource Energy.  To limit TEP, UNS Gas, UNS Electric and MEG’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions.  To limit TEP, UNS Gas, UNS Electric and MEG’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.

Commodity Price Risk

We are exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, coal and emission allowances.

TEP

Purchases and Sales of Energy

To manage its exposure to energy price risk, TEP enters into forward contracts to buy or sell energy at a specified price and future delivery period.  Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified market approach to provide a balance between long-term, mid-term and spot energy sales.  TEP generally enters into forward purchases during its summer peaking period to ensure it can meet its load and reserve requirements and account for other contracts and resource contingencies.  TEP also enters into limited forward purchases and sales to optimize its resource portfolio and take advantage of locational differences in price.  These positions are managed on both a volumetric and dollar basis and are closely monitored using risk management policies and procedures overseen by the Risk Management Committee.  For example, the risk management policies provide that TEP should not take a short physical position in the third quarter and must have owned generation backing up all physical forward sales positions at the time the sale is made.  TEP’s risk management policies also restrict entering into forward positions with maturities extending beyond the end of the next calendar year except for approved hedging purposes.

TEP’s risk management policies also allow for financial purchases and sales of energy subject to specified risk parameters established and monitored by the Risk Management Committee.  These include financial trades in a futures account on an exchange, with the intent of optimizing market opportunities.

The majority of TEP’s forward contracts are considered to be “normal purchases and sales” of electric energy and are therefore not accounted for as derivatives under FAS 133.  TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered.  From time to time, however, TEP enters into forward contracts that meet the definition of a derivative under FAS 133.  When TEP has derivative forward contracts, it marks them to market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other Southwestern U.S. trading hubs.  TEP believes that these broker quotations used to calculate the mark-to-market values represent accurate measures of the fair values of TEP’s positions because of the short-term nature of TEP’s positions, as limited by risk management policies, and the liquidity in the short-term market.

To adjust the value of its derivative forward power sales and purchases, classified as cash flow hedges, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains and losses:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
	-In Millions-		-In Millions-
Unrealized Gain	$   1	$   6	$   -	$   7

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TEP also reported the following net unrealized gains and losses on forward power sales and purchases in Wholesale Sales.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
	-In Millions-		-In Millions-
Unrealized Gain	$    -	$   1	$    -	$   1

Natural Gas

TEP is also subject to commodity price risk from changes in the price of natural gas.  In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers and to meet local reliability needs.  Some of these purchased power contracts are price indexed to natural gas prices.  Short-term and spot power purchase prices are also closely correlated to natural gas prices.  Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed purchase power and spot market purchases with fixed price contracts for a maximum of three years.  TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.

In the first nine months of 2007, the average market price of natural gas was $6.13 per MMBtu, or 1% lower than the same period in 2006.  The table below summarizes TEP’s gas generation output and purchased power for the first nine months of 2007 and 2006.

Nine Months Ended September 30,	2007	2006	2007	2006
	-MWhs-		% of Total Resources
Gas-Fired Generation	841,000	678,000	8%	6%
Purchased Power	1,772,000	1,411,000	16%	14%

To adjust the value of its derivative gas swap contracts, classified as cash flow hedges, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains and losses:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
	-In Millions-		-In Millions-
Unrealized (Loss) Gain	$  (3)	$ (1)	$  (6)	$ (15)

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 -
Source of Fair Value At Sept. 30, 2007	Maturity 0 – 6 months	Maturity 6 – 12 months	Maturity over 1 yr.	Total Unrealized Gain (Loss)
Prices actively quoted	$     2	$   (1)	$    -	$      1
Prices based on models and other valuation methods	-	-	-	-
Total	$     2	$   (1)	$    -	$      1

Sensitivity Analysis of Derivatives

TEP uses sensitivity analysis to measure the impact of an unfavorable change in market prices on the fair value of its derivative forward contracts.  Unrealized gains and losses related to TEP’s derivative contracts that are not

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cash flow hedges are reported on the income statement.  Unrealized gains and losses related to derivative contracts that are cash flow hedges are reported in Other Comprehensive Income; the unrealized gains and losses are reversed as contracts settle and realized gains or losses are recorded. The chart below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%, as of September 30, 2007.

	- Millions of Dollars -
Change in Market Price As of September 30, 2007	10% Increase	10% Decrease
Non-Cash Flow Hedges
Forward power sales and purchase contracts	$ 1	$(1)
Gas swap agreements	-	-
Cash Flow Hedges
Forward power sales and purchase contracts	$ (1)	$ 1
Gas swap agreements	3	(3)

Coal

TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants.  The commodity price risk from changes in the price of coal have not changed materially from the commodity price risks reported in our 2006 Annual Report on Form 10-K.

UNS Gas

UNS Gas is subject to commodity price risk, primarily from the 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.  UNS Gas further reduces this risk by purchasing forward fixed price contracts for a portion of its projected gas needs under its Price Stabilization Plan.  UNS Gas purchases at least 45% of its estimated gas needs in this manner.

UNS Electric

UNS Electric is currently not exposed to commodity price risk for its purchase of electricity as it has a fixed price full-requirements supply agreement with PWMT and a PPFAC mechanism which fully recovers the costs incurred under such contract on a timely basis.  This supply agreement with PWMT expires in May 2008 and UNS Electric is in the process of replacing this energy resource.

In 2006 and 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric estimates its future minimum payments under these contracts to be $48 million in 2008, $59 million in 2009, $38 million in 2010, $15 million in 2011, $8 million in 2012, and $8 million thereafter based on natural gas prices at the date of the contracts.

Because a portion of the costs under these contracts will vary from period to period based on the market price of gas, the PPFAC, as currently structured, may not provide recovery of the costs incurred under these new contracts on a timely basis.

In May 2007, UNS Electric began hedging a portion of its total natural gas exposure from gas-indexed purchase power agreements that begin in June 2008 with fixed price contracts.  In addition, UNS Electric began hedging a portion of its anticipated natural gas exposure from plant fuel for the period June 2008 and beyond.  UNS Electric currently has approximately 24% of this aggregate summer exposure hedged for the summer of 2008.  UNS Electric will obtain its remaining gas and purchased power needs through a combination of additional forward purchases and purchases in the short-term and spot markets.

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For UNS Electric’s forward power purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $15 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $15 million.

MEG

MEG trades Emission Allowances and related instruments; however, its current activities consist of managing a small number of remaining positions which are expected to close by early 2008.  We manage the market risk of this line of business by setting notional limits by product, as well as limits to the potential change in fair market value under a 33% change in price or volatility.  We closely monitor MEG’s trading activities, which include swap agreements, options and forward contracts, using risk management policies and procedures overseen by the Risk Management Committee.

MEG marks its trading positions to market on a daily basis using actively quoted prices obtained from brokers and options pricing models for positions that extend through 2007.  As of September 30, 2007 and December 31, 2006, the fair value of MEG’s trading assets combined with Emission Allowances it holds in escrow was $11 million and $11 million, respectively.  The fair value of MEG’s trading liabilities was $5 million at September 30, 2007 and $5 million at December 31, 2006.  For the first nine months of 2007, MEG reflected a $1 million unrealized loss and a $1 million realized gain on its income statement, compared with an unrealized loss of $3 million and a realized gain of $3 million in the same period last year.  For MEG’s remaining trading contracts at September 30, 2007, a 10% change in market prices would result in a gain or loss of less than $1 million.

	Unrealized Gain (Loss) of MEG’s Trading Activities
	- Millions of Dollars -
Source of Fair Value At Sept. 30, 2007	Maturity 0 – 6 months	Maturity  6 – 12 months	Maturity over 1 yr.	Total Unrealized Gain (Loss)
Prices actively quoted	$  7	$ -	$ -	$ 7
Prices based on models and other valuation methods	3	-	-	3
Total	$10	$ -	$ -	$10

Credit Risk

UniSource Energy is exposed to credit risk in its energy-related marketing and trading activities related to potential nonperformance by counterparties.  We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standard agreement which allows for the netting of current period exposures to and from a single counterparty.

We calculate counterparty credit exposure by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts.  As of September 30, 2007, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $14 million.  Approximately $2 million of TEP’s exposure is to non-investment grade companies.  TEP had two counterparties with exposures of greater than 10% of its total credit exposure, totaling approximately $7 million.

TEP maintains a margin account with a broker to support certain risk management and trading activities.  At September 30, 2007, TEP had approximately $1 million in that margin account.

MEG’s total credit exposure related to its trading activities was $6 million and was concentrated primarily with two counterparties.  MEG has no credit exposure to non-investment grade counterparties.

UNS Gas is subject to credit risk from non-performance by its supply counterparty, BP Energy (BP), to the extent that this contract has a mark-to-market value in favor of UNS Gas.  As September 30, 2007, UNS Gas had purchased under fixed price contracts approximately 53% of the expected monthly consumption for the 2007/2008 winter season (November through March) and approximately 22% of its expected consumption for the 2008/2009 winter season.  At September 30, 2007, UNS Gas had no mark-to-market credit exposure under its supply contract with BP.

UNS Electric has begun to enter into energy purchase agreements to replace the full requirements contract it has with PWMT that expires in May 2008, as well as gas hedging contracts to hedge the risk in its gas-indexed power

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purchase agreements.  To the extent that such contracts have a positive mark-to-market value, UNS Electric would be exposed to credit risk under those contracts.  At September 30, 2007, UNS Electric had approximately $3 million in credit exposure under such contracts.

ITEM 4. – CONTROLS AND PROCEDURES

UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource Energy 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 September 30, 2007.  Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UniSource Energy 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 and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UniSource Energy 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 or TEP’s internal control over financial reporting during the third quarter of 2007 that has materially affected, or is reasonably likely to materially affect, UniSource Energy or TEP’s internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. – LEGAL PROCEEDINGS

There are no pending material legal proceedings to which the Company is a party, other than routine litigation incidental to the business of the Company.  We discuss other legal proceedings in Note 7 ofNotes to Consolidated Financial Statements, Commitments and Contingencies.

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 2006 Annual Report on Form 10-K.

ITEM 5. – OTHER INFORMATION
NON-GAAP MEASURES

Adjusted EBITDA

Adjusted EBITDA represents EBITDA excluding the discontinued operations.  EBITDA is earnings before interest, taxes, depreciation and amortization.  Adjusted EBITDA is presented here as a measure of liquidity because it can be used as an indication of a company’s ability to incur and service debt and is commonly used as an analytical indicator in our industry. Adjusted EBITDA measures presented may not be comparable to similarly titled measures used by other companies.  Adjusted EBITDA is not a measurement presented in accordance with United States generally accepted accounting principles (GAAP), and we do not intend Adjusted EBITDA to represent cash flows from operations as defined by GAAP. Adjusted EBITDA should not be considered to be an alternative to cash flows from operations or any other items calculated in accordance with GAAP or an indicator of our operating performance.

UniSource Energy and TEP view Adjusted EBITDA, a non-GAAP financial measure, as a liquidity measure.  The most directly comparable GAAP measure to Adjusted EBITDA is Net Cash Flows - Operating Activities.

Adjusted EBITDA and Net Cash Flows - Operating Activities

	UniSource Energy
	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	- Millions of Dollars -
Adjusted EBITDA (non-GAAP)	$	138		$	144		$	341		$	366
Net Cash Flows - Operating Activities (GAAP)	$	84		$	72		$	204		$	197
Net Cash Flows - Investing Activities (GAAP)	$	(47	)	$	(34	)	$	(153	)	$	(168	)
Net Cash Flows - Financing Activities (GAAP)	$	(74	)	$	(88	)	$	(95	)	$	(89	)

	TEP
	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	- Millions of Dollars -
Adjusted EBITDA (non-GAAP)	$	126		$	136		$	303		$	331
Net Cash Flows - Operating Activities (GAAP)	$	70		$	45		$	163		$	143
Net Cash Flows - Investing Activities (GAAP)	$	(25	)	$	(18	)	$	(97	)	$	(138	)
Net Cash Flows - Financing Activities (GAAP)	$	(77	)	$	(63	)	$	(75	)	$	(45	)

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Reconciliation of Adjusted EBITDA to Cash Flows from Operations

	UniSource Energy
	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	- Millions of Dollars -
Adjusted EBITDA (non-GAAP) (1)	$	138		$	144		$	341		$	366
Amounts from the Income Statements:
Less:  Income Taxes		16			18			28			39
Less:  Total Interest Expense		34			41			103			115
Changes in Assets and Liabilities and Other Non-Cash Items		(4	)		(13	)		(6	)		(15	)
Net Cash Flows - Operating Activities (GAAP)		84			72			204			197
Net Cash Flows - Investing Activities (GAAP)		(47	)		(34	)		(153	)		(168	)
Net Cash Flows - Financing Activities (GAAP)		(74	)		(88	)		(95	)		(89	)
Net Increase (Decrease) in Cash and Cash Equivalents (GAAP)	$	(37	)	$	(50	)	$	(44	)	$	(59	)

	TEP
	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	- Millions of Dollars -
Adjusted EBITDA (non-GAAP) (1)	$	126		$	136		$	303		$	331
Amounts from the Income Statements:
Less:  Income Taxes		16			19			25			38
Less:  Total Interest Expense		28			34			87			96
Changes in Assets and Liabilities and Other Non-Cash Items		(12	)		(38	)		(28	)		(54	)
Net Cash Flows - Operating Activities (GAAP)		70			45			163			143
Net Cash Flows - Investing Activities (GAAP)		(25	)		(18	)		(97	)		(138	)
Net Cash Flows - Financing Activities (GAAP)		(77	)		(63	)		(75	)		(45	)
Net Increase (Decrease) in Cash and Cash Equivalents (GAAP)	$	(31	)	$	(36	)	$	(9	)	$	(40	)

⁽¹⁾ Adjusted EBITDA was calculated as follows:

	UniSource Energy
	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	- Millions of Dollars -
Net Income (GAAP)	$	25	$	28	$	42	$	55
Amounts from the Income Statements:
Less: Discontinued Operations – Net of Tax		-		-		-		(3	)
Plus:  Income Taxes		16		18		28		39
Total Interest Expense		34		41		103		115
Depreciation and Amortization		35		33		103		97
Amortization of Transition Recovery Asset		26		22		60		51
Depreciation included in Fuel and Other O&M
Expense (see Note 13 of Notes to Consolidated
Financial Statements)		2		2		5		6
Adjusted EBITDA (non-GAAP)	$	138	$	144	$	341	$	366

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	TEP
	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	- Millions of Dollars -
Net Income (GAAP)	$	26	$	30	$	39	$	57
Amounts from the Income Statements:
Plus:  Income Taxes		16		19		25		38
Total Interest Expense		28		34		87		96
Depreciation and Amortization		29		29		88		84
Amortization of Transition Recovery Asset		26		22		60		51
Depreciation included in Fuel and Other O&M
Expense (see Note 13 of Notes to Consolidated
Financial Statements)		1		2		4		5
Adjusted EBITDA (non-GAAP)	$	126	$	136	$	303	$	331

Net Debt and Total Debt and Capital Lease Obligations - TEP

Net Debt represents the current and non-current portions of TEP’s long-term debt and capital lease obligations less investment in lease debt.  Investment in lease debt is subtracted because it represents TEP’s ownership of the debt component of its own capital lease obligations.  Net Debt measures presented may not be comparable to similarly titled measures used by other companies.  Net Debt is not a measurement presented in accordance with GAAP and is not intended to represent debt as defined by GAAP.  Net Debt should not be considered to be an alternative to debt or any other items calculated in accordance with GAAP.

	As of September 30, 2007		As of December 31, 2006
	- Millions of Dollars -
Net Debt (non-GAAP)	$	1,304	$	1,335
Total Debt and Capital Lease Obligations (GAAP)	$	1,409	$	1,468

Reconciliation of Total Debt and Capital Lease Obligations to Net Debt

	As of September 30, 2007			As of December 31, 2006
	- Millions of Dollars -
Total Debt (GAAP)	$	821		$	821
Capital Lease Obligations		529			588
Current Portion – Capital Lease Obligations		59			59
Total Debt and Capital Lease Obligations (GAAP)		1,409			1,468
Investment in Lease Debt		(105	)		(133	)
Net Debt (non-GAAP)	$	1,304		$	1,335

Ratio of Earnings to Fixed Charges

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

	Nine Months Ended	Twelve Months Ended
	September 30, 2007	September 30, 2007
UniSource Energy	1.649	1.601
TEP	1.714	1.602

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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:  November 2, 2007	/s/	Kevin P. Larson
		Kevin P. Larson Senior Vice President and Principal Financial Officer
	TUCSON ELECTRIC POWER COMPANY   (Registrant)
Date:  November 2, 2007	/s/	Kevin P. Larson
		Kevin P. Larson Senior Vice President and Principal Financial Officer

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EXHIBIT INDEX

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 James S. Pignatelli.

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 James S. Pignatelli.

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).

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

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