TEP & UNS 10Q

10-Q 1 tepuns10q.htm 10-Q TEP & UNS 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2013



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

For the transition period from to .



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

1-5924	TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) 88 East Broadway Boulevard Tucson, AZ 85701 (520) 571-4000	86-0062700

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



UNS Energy Corporation	Yes x	No ¨

Tucson Electric Power Company	Yes x	No ¨

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



UNS Energy Corporation	Yes x	No ¨

Tucson Electric Power Company	Yes x	No ¨

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



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



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

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



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

As of April 17, 2013, 41,459,272 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of April 17, 2013, Tucson Electric Power Company had 32,139,434 shares of common stock outstanding, no par value, all of which were held by UNS Energy Corporation.

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

Table of Contents



Definitions	v

Reports of Independent Registered Public Accounting Firm	1

PART I
Item 1. – Financial Statements	3
UNS Energy Corporation	3
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	4
Condensed Consolidated Statements of Cash Flows	5
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statement of Changes in Stockholders’ Equity	8
Tucson Electric Power Company	9
Condensed Consolidated Statements of Income (Loss)	9
Condensed Consolidated Statements of Comprehensive Income (Loss)	10
Condensed Consolidated Statements of Cash Flows	11
Condensed Consolidated Balance Sheets	12
Condensed Consolidated Statement of Changes in Stockholder’s Equity	14
Notes to Condensed Consolidated Financial Statements - Unaudited	15
Note 1. Financial Statement Presentation	15
Note 2. Regulatory Matters	16
Note 3. Business Segments	17
Note 4. Debt	18
Note 5. Income Taxes	19
Note 6. Commitments, Contingencies, and Environmental Matters	19
Note 7. Employee Benefit Plans	24
Note 8. Share-Based Compensation Plans	24
Note 9. Fair Value Measurements	24
Note 10. UNS Energy Earnings Per Share	29
Note 11. Supplemental Cash Flow Information	30
Note 12. Derivative Instruments and Hedging Activities	31
Note 13. Changes in Accumulated Other Comprehensive Income by Component	34
Note 14. Recently Issued Accounting Pronouncement	35
Note 15. Review by Independent Registered Public Accounting Firm	35

Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
UNS Energy Corporation	36
Overview of Consolidated Business	36
Outlook and Strategies	36
Results of Operations	37
Liquidity and Capital Resources	38
Tucson Electric Power Company	41
Results of Operations	41
Factors Affecting Results of Operations	45
Liquidity and Capital Resources	49
UNS Gas	52
Results of Operations	52

iii



Factors Affecting Results of Operations	53
Liquidity and Capital Resources	54
UNS Electric	56
Results of Operations	56
Factors Affecting Results of Operations	57
Liquidity and Capital Resources	59
Other Non-Reportable Business Segments	60
Results of Operations	60
Factors Affecting Results of Operations	60
Critical Accounting Estimates	61
Recently Issued Accounting Pronouncement	61
Safe Harbor for Forward-Looking Statements	61

PART II – OTHER INFORMATION
Item 1. – Legal Proceedings	61
Item 1A. – Risk Factors	62
Item 2. – Unregistered Sale of Equity Securities and Use of Proceeds	62
Item 3. – Quantitative and Qualitative Disclosures about Market Risk	62
Item 4. – Controls and Procedures	63
Item 5. – Other Information	63
Ratio of Earnings to Fixed Charges	63
Environmental Matters	63
Item 6. Exhibits	64

Signatures	65
Exhibit Index	66

DEFINITIONS

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




1992 Mortgage		TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York Mellon, successor trustee, as supplemented
2010 TEP Reimbursement Agreement		Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2010 UNS Electric Rate Order		A rate order issued by the ACC resulting in a new rate structure for UNS Electric, effective September 1, 2010
2013 Settlement Agreement		The proposed settlement agreement between TEP, ACC Staff, and parties to the pending rate case which requires approval of the ACC before rates can become effective
ACC		Arizona Corporation Commission
ALJ		Administrative Law Judge
AOCI		Accumulated Other Comprehensive Income
APS		Arizona Public Service Company
BART		Best Available Retrofit Technology
Base O&M		A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business
Base Rates		The portion of TEP’s and UNS Electric’s Retail Rates attributed to generation, transmission, distribution costs, and customer charge; and UNS Gas’ delivery costs and customer charge. Base Rates exclude costs that are passed through to customers for fuel and purchased energy costs
BMGS		Black Mountain Generating Station
Btu		British thermal unit(s)
Capacity		The ability to produce power; the most power a unit can produce or the maximum that can be taken under a contract, measured in megawatts
CC&N		Certificate of Convenience and Necessity
Common Stock		UNS Energy Corporation’s common stock, without par value
Company		UNS Energy Corporation and its subsidiaries
Convertible Senior Notes		UNS Energy Corporation’s 4.5% Convertible Senior Notes
DSM		Demand Side Management
ECA		Environmental Compliance Adjustor
Electric EE Standards		Electric Energy Efficiency Standards
Energy		The amount of power produced over a given period of time measured in megawatt-hours
EPA		Environmental Protection Agency
EPS		Earnings Per Share
ESP		Electric Service Providers
FERC		Federal Energy Regulatory Commission
FIP		Federal Implementation Plan
FVRB		Fair Value Rate Base
Four Corners		Four Corners Generating Station
GAAP		Generally Accepted Accounting Principles
Gas EE Standards		Gas Energy Efficiency Standards
GBtu		Billion British thermal units
GWh		Gigawatt-hour(s)
Heating Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65
IRS		Internal Revenue Service
kV		Kilo-volt



kWh		Kilowatt-hour(s)
LFCR		Lost Fixed Cost Recovery Mechanism
LOC		Letter of Credit
LIBOR		London Interbank Offered Rate
Millennium		Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation
MMBtu		Million British thermal units
Mortgage Bonds		Mortgage Bonds issued under the 1992 Mortgage
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Navajo		Navajo Generating Station
Net Cash Flows after Capital Expenditures		A non-GAAP financial measure that compares capital expenditures relative to cash flows from operating activities
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations		A non-GAAP financial measure that compares capital expenditures and required payments on capital lease obligations relative to cash flows from operating activities
NSP		Negotiated Sales Program
NTUA		Navajo Tribal Utility Authority
NOx		Nitrogen Oxide
O&M		Operations and Maintenance
OATT		Open Access Transmission Tariff
OCRB		Original Cost Rate Base
PBI		Performance-Based Incentives paid to retail customers with solar installations based on metered renewable energy production over periods of 10 to 20 years
PGA		Purchased Gas Adjustor, a Retail Rate mechanism designed to recover the cost of gas purchased for retail gas customers
PNM		Public Service Company of New Mexico
PNMR		PNM Resources, Incorporated, PNM’s parent company
PPA		Power Purchase Agreement
PPFAC		Purchased Power and Fuel Adjustment Clause
PSD		Prevention of Significant Deterioration
REC		Renewable Energy Credit
RES		Renewable Energy Standard
Retail Margin Revenues		A non-GAAP financial measure that demonstrates the underlying revenue trend and performance of our core utility businesses
Regional Haze Rules		Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
Retail Rates		Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service
Rules		Retail Electric Competition Rules established by the ACC in 1999
San Juan		San Juan Generating Station
SCR		Selective Catalytic Reduction
SEC		Securities and Exchange Commission
SERP		Supplemental Executive Retirement Plan
SES		Southwest Energy Solutions, a wholly-owned subsidiary of Millennium
SJCC		San Juan Coal Company
SMCRA		Surface Mine Control and Reclamation Act
SNCR		Selective Non-Catalytic Reduction
SO2		Sulfur Dioxide



Springerville		Springerville Generating Station
Springerville Common Facilities		Facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities Leases		Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1		Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases		Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2		Unit 2 of the Springerville Generating Station
Springerville Unit 3		Unit 3 of the Springerville Generating Station
Springerville Unit 4		Unit 4 of the Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sundt		H. Wilson Sundt Generating Station
Sundt Unit 4		Unit 4 of the H. Wilson Sundt Generating Station
TCA		Transmission Cost Adjustor
Tenth Circuit		United States Court of Appeals
TEP		Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
TEP Credit Agreement		Second Amended and Restated Credit Agreement between TEP and a syndicate of banks, dated as of November 9, 2010 (as amended)
TEP Revolving Credit Facility		Revolving credit facility under the TEP Credit Agreement
Therm		A unit of heating value equivalent to 100,000 Btus
Tri-State		Tri-State Generation and Transmission Association, Inc.
UED		UniSource Energy Development Company, a wholly-owned subsidiary of UNS Energy Corporation
UES		UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy, and intermediate holding company established to own the operating companies UNS Gas and UNS Electric
UNS Credit Agreement		Second Amended and Restated Credit Agreement between UNS Energy Corporation and a syndicate of banks, dated as of November 9, 2010 (as amended)
UNS Electric		UNS Electric, Inc., a wholly-owned subsidiary of UES
UNS Energy		UNS Energy Corporation (formally known as UniSource Energy Corporation)
UNS Gas		UNS Gas, Inc., a wholly-owned subsidiary of UES
UNS Gas/UNS Electric Revolver		Revolving credit facility under the Second Amended and Restated Credit Agreement among UNS Gas and UNS Electric as borrowers, UES as guarantor, and a syndicate of banks, dated as of November 9, 2010 (as amended)

vii

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

UNS Energy Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of UNS Energy Corporation and its subsidiaries (the “Company”) as of March 31, 2013, and the related condensed consolidated statements of income for the three-month periods ended March 31, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month periods ended March 31, 2013 and 2012, the condensed consolidated statement of changes in stockholders’ equity for the three-month period ended March 31, 2013 and the condensed consolidated statements of cash flows for the three-month periods ended March 31, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.

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

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

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

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

April 29, 2013

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 March 31, 2013, and the related condensed consolidated statements of income (loss) for the three-month periods ended March 31, 2013 and 2012, the condensed consolidated statements of comprehensive income (loss) for the three-month periods ended March 31, 2013 and 2012, the condensed consolidated statement of changes in stockholder’s equity for the three-month period ended March 31, 2013 and the condensed consolidated statements of cash flows for the three-month periods ended March 31, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.

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

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

April 29, 2013

Table of Contents

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended
	March 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
	(Except Per Share Amounts)
Operating Revenues
Electric Retail Sales	$	220,860		$	205,431
Electric Wholesale Sales	34,398			33,617
Gas Retail Sales	50,988			50,209
Other Revenues	25,895			26,130
Total Operating Revenues	332,141			315,387
Operating Expenses
Fuel	81,689			70,735
Purchased Energy	64,159			59,790
Transmission	3,186			2,826
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(5,368		)	(2,561		)
Total Fuel and Purchased Energy	143,666			130,790
Operations and Maintenance	89,901			94,317
Depreciation	36,300			34,984
Amortization	8,289			8,664
Taxes Other Than Income Taxes	14,090			12,229
Total Operating Expenses	292,246			280,984
Operating Income	39,895			34,403
Other Income (Deductions)
Interest Income	10			258
Other Income	2,805			3,095
Other Expense	(572		)	(466		)
Total Other Income (Deductions)	2,243			2,887
Interest Expense
Long-Term Debt	18,254			19,135
Capital Leases	6,249			8,296
Other Interest Expense, Net of Interest Capitalized	(1,068		)	175
Total Interest Expense	23,435			27,606
Income Before Income Taxes	18,703			9,684
Income Tax Expense	7,358			3,208
Net Income	$	11,345		$	6,476
Weighted-Average Shares of Common Stock Outstanding (000)
Basic	41,540			38,031
Diluted	41,875			38,321
Earnings Per Share
Basic	$	0.27		$	0.17
Diluted	$	0.27		$	0.17
Dividends Declared Per Share	$	0.435		$	0.43

See Notes to Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended
	March 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
Comprehensive Income
Net Income	$	11,345	$	6,476
Other Comprehensive Income

Unrealized Gain (Loss) on Cash Flow Hedges, net of $(31) and $370 income taxes	47		(564		)
Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(370) and $(364) income taxes	565		556
Supplemental Executive Retirement Plan (SERP) Benefit Adjustments, net of $(42) and $19 income taxes	68		108
Total Other Comprehensive Income, Net of Income Taxes	680		100
Total Comprehensive Income	$	12,025	$	6,576

See Notes to Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three Months Ended March 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	253,747		$	240,164
Cash Receipts from Electric Wholesale Sales	43,538			43,034
Cash Receipts from Gas Retail Sales	59,849			62,064
Cash Receipts from Operating Springerville Units 3 & 4	25,032			25,169
Cash Receipts from Gas Wholesale Sales	3,152			377
Interest Received	515			1,528
Other Cash Receipts	6,137			6,464
Fuel Costs Paid	(76,321		)	(76,769		)
Payment of Operations and Maintenance Costs	(57,173		)	(70,967		)
Purchased Energy Costs Paid	(73,761		)	(72,353		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(32,237		)	(31,952		)
Wages Paid, Net of Amounts Capitalized	(36,306		)	(38,016		)
Interest Paid, Net of Amounts Capitalized	(17,784		)	(20,490		)
Capital Lease Interest Paid	(16,123		)	(19,369		)
Other Cash Payments	(1,212		)	(2,314		)
Net Cash Flows—Operating Activities	81,053			46,570
Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt	9,104			19,278
Insurance Proceeds for Replacement Assets	—			2,875
Other Cash Receipts	2,911			4,047
Capital Expenditures	(81,228		)	(78,931		)
Other Cash Payments	(5,304		)	(2,223		)
Net Cash Flows—Investing Activities	(74,517		)	(54,954		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	66,000			198,000
Other Cash Receipts	2,690			1,463
Repayments of Borrowings Under Revolving Credit Facilities	(35,000		)	(92,000		)
Payments of Capital Lease Obligations	(81,281		)	(73,993		)
Common Stock Dividends Paid	(18,035		)	(16,322		)
Repayments of Long-Term Debt	—			(8,448		)
Other Cash Payments	(928		)	(1,603		)
Net Cash Flows—Financing Activities	(66,554		)	7,097
Net Decrease in Cash and Cash Equivalents	(60,018		)	(1,287		)
Cash and Cash Equivalents, Beginning of Year	123,918			76,390
Cash and Cash Equivalents, End of Period	$	63,900		$	75,103

See Note 11 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,			December 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	5,039,638		$	5,005,768
Utility Plant Under Capital Leases	582,669			582,669
Construction Work in Progress	156,178			128,621
Total Utility Plant	5,778,485			5,717,058
Less Accumulated Depreciation and Amortization	(1,943,865		)	(1,921,733		)
Less Accumulated Amortization of Capital Lease Assets	(499,784		)	(494,962		)
Total Utility Plant—Net	3,334,836			3,300,363
Investments and Other Property
Investments in Lease Equity	36,302			36,339
Other	37,594			36,537
Total Investments and Other Property	73,896			72,876
Current Assets
Cash and Cash Equivalents	63,900			123,918
Accounts Receivable—Customer	92,015			93,742
Unbilled Accounts Receivable	39,911			53,568
Allowance for Doubtful Accounts	(6,455		)	(6,545		)
Materials and Supplies	90,790			93,322
Fuel Inventory	62,977			62,019
Deferred Income Taxes—Current	34,705			34,260
Regulatory Assets—Current	45,950			51,619
Investments in Lease Debt	—			9,118
Derivative Instruments	5,733			3,165
Other	25,450			33,567
Total Current Assets	454,976			551,753
Regulatory and Other Assets
Regulatory Assets—Noncurrent	188,612			191,077
Other Assets	25,568			24,360
Total Regulatory and Other Assets	214,180			215,437
Total Assets	$	4,077,888		$	4,140,429

See Notes to Condensed Consolidated Financial Statements.

(Continued)

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,		December 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,059,405	$	1,065,465
Capital Lease Obligations	179,610		262,138
Long-Term Debt	1,504,473		1,498,442
Total Capitalization	2,743,488		2,826,045
Current Liabilities
Current Obligations Under Capital Leases	95,587		90,583
Borrowings Under Revolving Credit Facilities	25,000		—
Accounts Payable—Trade	86,959		107,740
Accrued Taxes Other than Income Taxes	54,473		41,939
Interest Accrued	18,217		31,950
Accrued Employee Expenses	20,247		24,094
Regulatory Liabilities—Current	44,350		43,516
Customer Deposits	34,826		34,048
Derivative Instruments	7,934		14,742
Other	14,836		10,517
Total Current Liabilities	402,429		399,129
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	386,800		364,756
Regulatory Liabilities—Noncurrent	289,197		279,111
Pension and Other Retiree Benefits	161,066		159,401
Derivative Instruments	11,363		12,709
Other	83,545		99,278
Total Deferred Credits and Other Liabilities	931,971		915,255
Commitments, Contingencies, and Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$	4,077,888	$	4,140,429

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY



	Common Shares Outstanding*	Common Stock			Accumulated Earnings			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Thousands of Shares	(Unaudited) Thousands of Dollars
Balances at December 31, 2012	41,344	$	882,138		$	193,117		$	(9,790	)	$	1,065,465
Comprehensive Income
2013 Year-to-Date Net Income					11,345						11,345
Other Comprehensive Income, net of $(443) income taxes								680			680
Total Comprehensive Income											12,025
Dividends, Including Non-Cash Dividend Equivalents					(18,226		)				(18,226		)
Shares Issued for Stock Options	16	589									589
Shares Issued Under Performance Share Awards	57	—									—
Other		(448		)							(448		)
Balances at March 31, 2013	41,417	$	882,279		$	186,236		$	(9,110	)	$	1,059,405

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

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)



	Three Months Ended
	March 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Operating Revenues
Electric Retail Sales	$	184,881		$	166,331
Electric Wholesale Sales	34,398			29,766
Other Revenues	28,472			27,881
Total Operating Revenues	247,751			223,978
Operating Expenses
Fuel	80,798			69,974
Purchased Power	18,928			13,626
Transmission	865			963
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(2,360		)	(7,686		)
Total Fuel and Purchased Energy	98,231			76,877
Operations and Maintenance	77,824			82,466
Depreciation	28,558			27,467
Amortization	9,222			9,591
Taxes Other Than Income Taxes	11,169			9,679
Total Operating Expenses	225,004			206,080
Operating Income	22,747			17,898
Other Income (Deductions)
Interest Income	(4		)	26
Other Income	2,206			2,461
Other Expense	(2,245		)	(1,493		)
Total Other Income (Deductions)	(43		)	994
Interest Expense
Long-Term Debt	14,573			13,916
Capital Leases	6,249			8,296
Other Interest Expense, Net of Interest Capitalized	(853		)	110
Total Interest Expense	19,969			22,322
Income (Loss) Before Income Taxes	2,735			(3,430		)
Income Tax Expense (Benefit)	1,257			(1,969		)
Net Income (Loss)	$	1,478		$	(1,461	)

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



	Three Months Ended
	March 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
Comprehensive Income (Loss)
Net Income (Loss)	$	1,478	$	(1,461	)
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Cash Flow Hedges, net of $(29) and $323 income taxes	45		(493		)
Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(350) and $(348) income taxes	535		531
SERP Benefit Adjustments, net of $(42) and $19 income taxes	68		108
Total Other Comprehensive Income, Net of Income Taxes	648		146
Total Comprehensive Income (Loss)	$	2,126	$	(1,315	)

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three Months Ended March 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	211,011		$	194,772
Cash Receipts from Electric Wholesale Sales	40,061			36,069
Cash Receipts from Operating Springerville Units 3 & 4	25,032			25,169
Cash Receipts from Gas Wholesale Sales	3,114			—
Reimbursement of Affiliate Charges	5,883			6,988
Interest Received	509			1,523
Other Cash Receipts	4,624			4,719
Fuel Costs Paid	(76,560		)	(76,473		)
Payment of Operations and Maintenance Costs	(54,791		)	(70,037		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(23,303		)	(22,299		)
Wages Paid, Net of Amounts Capitalized	(30,542		)	(31,728		)
Purchased Power Costs Paid	(17,417		)	(13,019		)
Interest Paid, Net of Amounts Capitalized	(11,239		)	(11,118		)
Capital Lease Interest Paid	(16,123		)	(19,369		)
Other Cash Payments	(860		)	(3,646		)
Net Cash Flows—Operating Activities	59,399			21,551
Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt	9,104			19,278
Insurance Proceeds for Replacement Assets	—			2,875
Other Cash Receipts	1,645			3,451
Capital Expenditures	(61,668		)	(66,845		)
Other Cash Payments	(4,556		)	(1,901		)
Net Cash Flows—Investing Activities	(55,475		)	(43,142		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	55,000			120,000
Other Cash Receipts	492			377
Repayments of Borrowings Under Revolving Credit Facility	(35,000		)	(25,000		)
Payments of Capital Lease Obligations	(81,281		)	(73,993		)
Repayments of Long-Term Debt	—			(6,535		)
Other Cash Payments	(874		)	(1,504		)
Net Cash Flows—Financing Activities	(61,663		)	13,345
Net Decrease in Cash and Cash Equivalents	(57,739		)	(8,246		)
Cash and Cash Equivalents, Beginning of Year	79,743			27,718
Cash and Cash Equivalents, End of Period	$	22,004		$	19,472

See Note 11 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,			December 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	4,371,895		$	4,348,041
Utility Plant Under Capital Leases	582,669			582,669
Construction Work in Progress	118,020			98,460
Total Utility Plant	5,072,584			5,029,170
Less Accumulated Depreciation and Amortization	(1,801,484		)	(1,783,787		)
Less Accumulated Amortization of Capital Lease Assets	(499,784		)	(494,962		)
Total Utility Plant—Net	2,771,316			2,750,421
Investments and Other Property
Investments in Lease Equity	36,302			36,339
Other	36,139			35,091
Total Investments and Other Property	72,441			71,430
Current Assets
Cash and Cash Equivalents	22,004			79,743
Accounts Receivable—Customer	70,717			71,813
Unbilled Accounts Receivable	28,730			33,782
Allowance for Doubtful Accounts	(4,494		)	(4,598		)
Accounts Receivable—Due from Affiliates	6,860			5,720
Materials and Supplies	77,787			80,377
Fuel Inventory	62,673			61,737
Deferred Income Taxes—Current	37,834			37,212
Regulatory Assets—Current	33,148			34,345
Investments in Lease Debt	—			9,118
Other	26,791			34,393
Total Current Assets	362,050			443,642
Regulatory and Other Assets
Regulatory Assets—Noncurrent	176,472			178,330
Other Assets	18,219			17,223
Total Regulatory and Other Assets	194,691			195,553
Total Assets	$	3,400,498		$	3,461,046

See Notes to Condensed Consolidated Financial Statements.

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,		December 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	863,053	$	860,927
Capital Lease Obligations	179,610		262,138
Long-Term Debt	1,223,474		1,223,442
Total Capitalization	2,266,137		2,346,507
Current Liabilities
Current Obligations Under Capital Leases	95,587		90,583
Borrowings Under Revolving Credit Facility	20,000		—
Accounts Payable—Trade	67,871		82,122
Accounts Payable—Due to Affiliates	2,587		3,134
Accrued Taxes Other than Income Taxes	43,128		33,060
Interest Accrued	16,380		26,965
Accrued Employee Expenses	17,518		20,715
Customer Deposits	25,546		24,846
Regulatory Liabilities—Current	19,958		20,822
Derivative Instruments	3,820		4,899
Other	11,134		7,085
Total Current Liabilities	323,529		314,231
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	331,221		319,216
Regulatory Liabilities—Noncurrent	249,095		241,189
Pension and Other Retiree Benefits	151,006		149,718
Derivative Instruments	10,108		10,565
Other	69,402		79,620
Total Deferred Credits and Other Liabilities	810,832		800,308
Commitments, Contingencies, and Environmental Matters (Note 6)
Total Capitalization and Other Liabilities	$	3,400,498	$	3,461,046

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY



	Common Stock		Capital Stock Expense			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	(Unaudited) Thousands of Dollars
Balances at December 31, 2012	$	888,971	$	(6,357	)	$	(12,157	)	$	(9,530	)	$	860,927
Comprehensive Income
2013 Year-to-Date Net Income						1,478						1,478
Other Comprehensive Income, net of $(421) income taxes									648			648
Total Comprehensive Income												2,126
Balances at March 31, 2013	$	888,971	$	(6,357	)	$	(10,679	)	$	(8,882	)	$	863,053

See Notes to Condensed Consolidated Financial Statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Unaudited

NOTE 1. FINANCIAL STATEMENT PRESENTATION

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

We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in UNS Energy's and TEP's Annual Reports on Form 10-K for the year ended December 31, 2012.

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

REVISION OF PRIOR PERIOD UNS ENERGY INCOME STATEMENT

During the first three quarters of 2012, we incorrectly reported UNS Electric's sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis. This error resulted in a $3 million equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statement for the three months ended March 31, 2012. This error had no impact on operating income, net income, retained earnings, or cash flows.

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



	UNS Energy
	Three Months Ended
	March 31, 2012
	As Reported		As Revised
	Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	37,104	$	33,617
Purchased Energy	63,276		59,790
Total Fuel and Purchased Energy	134,276		130,790
Total Operating Expenses	284,479		280,984

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In the first quarter of 2013, we adopted authoritative guidance that:


•	Requires additional disclosures for amounts reclassified out of accumulated other comprehensive income by component. See Note 13.


•	Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 12.


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

NOTE 2. REGULATORY MATTERS

RATES AND REGULATION

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

PENDING TEP RATE CASE

In July 2012, TEP filed a general rate case, on a cost-of-service basis, with the ACC requesting a Base Rate increase of approximately 15% to cover a revenue deficiency of $128 million. TEP requested a 7.74% return on Original Cost Rate Base (OCRB) of $1.5 billion and a 5.68% return on Fair Value Rate Base (FVRB) of $2.3 billion TEP also requested a 1.56% return on the fair value increment of rate base. The fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million.

TEP requested a Lost Fixed Cost Recovery (LFCR) mechanism to recover non-fuel costs that would go unrecovered due to lost kilowatt-hour (kWh) sales as a result of implementing the ACC's Electric Energy Efficiency Standards (Electric EE Standards) and the RES. TEP also requested a mechanism, which would be adjusted annually, to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases.

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

In February 2013, TEP, ACC Staff, and other parties to TEP's pending rate case proceeding entered into a proposed settlement agreement. The proposed settlement agreement requires the approval of the ACC before new rates can become effective. In the proposed settlement, TEP requested that the Purchased Power and Fuel Adjustment Clause (PPFAC) rate currently approved at 0.77 cents per kWh effective April 2012 be reset at the time new rates become effective.

In March 2013, hearings before an ACC Administrative Law Judge (ALJ) concluded. The ALJ will prepare a recommended opinion and order, which must be approved by the ACC before new rates may become effective.

PENDING UNS ELECTRIC RATE CASE

In December 2012, as required in the 2010 UNS Electric Rate Order, UNS Electric filed with the ACC a general rate case, on a cost-of-service basis, requesting a non-fuel Base Rate increase of $7.5 million, or 4.6%. UNS Electric requested a rate of return of 8.4% on an OCRB of approximately $217 million and a 6.7% rate of return on a FVRB of $286 million. UNS Electric also requested a 1.6% return on the fair value increment of rate base. The fair value increment of rate base represents the difference between OCRB and FVRB of approximately $69 million.

UNS Electric requested a LFCR mechanism to recover non-fuel costs that would go unrecovered due to lost kWh sales as a result of implementing Electric EE Standards and the RES. In addition to the LFCR mechanism, UNS Electric requested a

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

Transmission Cost Adjustor (TCA). The TCA is designed to track changes to UNS Electric's FERC-approved Open Access Transmission Tariff (OATT) rate which is updated annually and would allow UNS Electric to recover transmission costs in a timely manner.

REGULATORY ASSETS AND LIABILITIES

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



	March 31, 2013						December 31, 2012
	UNS Energy			TEP			UNS Energy			TEP
	Millions of Dollars
Regulatory Assets – Current ⁽¹⁾	$	46		$	33		52			$	34
Regulatory Assets – Noncurrent	189			176			191			178
Regulatory Liabilities—Current	(44		)	(20		)	(44		)	(21		)
Regulatory Liabilities – Noncurrent ⁽²⁾	(289		)	(249		)	(279		)	(241		)
Total Net Regulatory Assets (Liabilities)	$	(98	)	$	(60	)	$	(80	)	$	(50	)


⁽¹⁾	Regulatory Assets – Current on the balance sheet is lower due to a reduction in unrealized losses on energy contracts that are recoverable through the PPFAC/PGA when settled.


⁽²⁾	Regulatory Liabilities – Noncurrent on the balance sheet is higher due to the increase in the reserve for the net cost of removal related to interim and future retirements at TEP.

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF REGULATORY ACCOUNTING

We regularly assess whether we can continue to apply regulatory accounting to regulated operations, and we have concluded regulatory accounting is applicable. If we stopped applying regulatory accounting to our regulated operations, the following would occur:


•	Regulatory pension assets would be reflected in Accumulated Other Comprehensive Income (AOCI);


•	We would write off remaining regulatory assets as an expense and regulatory liabilities as income in the income statements;


•	At March 31, 2013, based on regulatory assets balances, net of regulatory liabilities:


•	TEP would have recorded an extraordinary after-tax gain of $113 million and an after-tax loss in AOCI of $77 million;


•	UNS Gas would have recorded an extraordinary after-tax gain of $25 million and an after-tax loss in AOCI of $2 million; and


•	UNS Electric would have recorded an extraordinary after-tax gain of $4 million and an after-tax loss in AOCI of $3 million.

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

NOTE 3. BUSINESS SEGMENTS

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


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


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


(3)	UNS Electric, a regulated electric utility.

Other includes UNS Energy and UniSource Energy Services holding companies, Millennium, and UniSource Energy Development.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

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



	Reportable Segments
	TEP			UNS Gas		UNS Electric		Other			Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Three Months Ended March 31, 2013:
Operating Revenues – External	$	244		$	52	$	36	$	—		$	—		$	332
Operating Revenues – Intersegment⁽¹⁾	4			—		1		4			(9		)	—
Income Before Income Taxes	3			12		4		—			—			19
Net Income	1			8		2		—			—			11
Three Months Ended March 31, 2012:
Operating Revenues – External	$	220		$	52	$	44	$	(1	)	$	—		$	315
Operating Revenues – Intersegment⁽¹⁾	4			1		—		4			(9		)	—
Income (Loss) Before Income Taxes	(3		)	9		5		(1		)	—			10
Net Income (Loss)	(1		)	5		3		(1		)	—			6

⁽¹⁾

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

NOTE 4. DEBT

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

TEP TAX-EXEMPT BONDS ISSUED

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

COVENANT COMPLIANCE

At March 31, 2013, we were in compliance with the terms of our loan and credit agreements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 5. INCOME TAXES

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



	UNS Energy						TEP
	Three Months Ended March 31,
	2013			2012			2013		2012
	Millions of Dollars
Federal Income Tax Expense (Benefit) at Statutory Rate	$	7		$	3		$	1	$	(1	)
State Income Tax Expense, Net of Federal Deduction	1			1			—		—
Cash Surrender Value of Life Insurance	—			(1		)	—		(1		)
Other	(1		)	—			—		—
Total Federal and State Income Tax Expense (Benefit)	$	7		$	3		$	1	$	(2	)

Uncertain Tax Positions

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



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

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

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

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

NOTE 6. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

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

TEP COMMITMENTS

Purchase Power Contracts

TEP entered into new forward purchase power commitments that will settle through December 2014. Some of these contracts are at fixed prices per MWh and others are indexed to natural gas prices. Based on projected market prices as of March 31, 2013, TEP's estimated minimum payment obligations for these purchases are $2 million in 2014.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

RES Recoverable Incentives

RES allows for utilities to make various incentive payments to customers who install distributed generation. The two types of incentives are up-front incentive payments and Performance-based Incentives (PBIs). Up-front incentive payments are distinguished by the following:


•	Residential and small commercial customers;


•	Small installations; and


•	Up-front payment upon installation.

PBIs are distinguished by the following:


•	Large commercial customers;


•	Large installations; and


•	Payment over the term of the contract.

RES Performance-based Incentives

TEP entered into new purchase agreements to purchase the environmental attributes, or RECs, from retail customers with solar installations. Payments for these RECs are termed PBIs and are paid in contractually agreed-upon intervals, usually quarterly, based on metered renewable energy production over periods ranging from 9 to 20 years. TEP's total obligation related to RES PBI payments over future periods increased by $4 million dollars from $62 million on December 31, 2012, to $66 million on March 31, 2013. PBIs are recoverable through the RES tariff.

UNS GAS COMMITMENTS

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

UNS ELECTRIC COMMITMENTS

Purchase Power Contracts

UNS Electric entered into new forward purchase power commitments that will settle through December 2014 at fixed prices per MWh. UNS Electric’s minimum payment obligations for these purchases are $1 million in 2014.

RES Performance-Based Incentives

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

TEP CONTINGENCIES

Claim Related to San Juan Generating Station

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

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed Motions to Dismiss with the Court for all claims asserted by EarthJustice in the amended complaint.

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

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo Generating Station (Navajo), San Juan, and Four Corners. TEP’s share of reclamation costs is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) recorded at March 31, 2013 and December 31, 2012, was $16 million.

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

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

Tucson to Nogales Transmission Line

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

Springerville Unit 1 Leases

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

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Resolution of Contingencies

Springerville Generating Station Unit 3 Outage

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

ENVIRONMENTAL MATTERS

Environmental Regulation

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

Hazardous Air Pollutant Requirements

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

Navajo

Based on the EPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which will be affected by final Best Available Retrofit Technology (BART) rules when issued.

San Juan

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

Four Corners

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

Springerville Generating Station

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

Sundt Generating Station

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

Regional Haze Rules

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

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

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Navajo

In January 2013, the EPA proposed an alternative BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. If SCR technology is ultimately required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.

San Juan

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

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

In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement that outlines an alternative to the FIP. The terms of the agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At March 31, 2013, the book value of TEP's share of San Juan Units 1 and 2 was $215 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. TEP cannot predict the ultimate outcome of this matter.

Four Corners

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

Springerville

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

Sundt

In December 2012, the EPA issued a proposed rule on provisions that had not been previously addressed in the Arizona State Implementation Plan related to regional haze. The EPA disagreed with the determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule. If the BART eligibility determination stands, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART determination. The EPA postponed its expected release of a proposed BART requirement for Sundt Unit 4 until September 6, 2013, with a final determination expected in February 2014.

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NOTE 7. EMPLOYEE BENEFIT PLANS

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



	Pension Benefits						Other Retiree Benefits
	Three Months Ended March 31,
	2013			2012			2013		2012
	Millions of Dollars

Service Cost	$	3		$	2		$	1	$	—
Interest Cost	4			4			1		1
Expected Return on Plan Assets	(5		)	(4		)	—		—
Actuarial Loss Amortization	2			2			—		—
Net Periodic Benefit Cost	$	4		$	4		$	2	$	1

NOTE 8. SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS AND PERFORMANCE SHARES

Restricted Stock Units

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

Performance Shares

In February 2013, the UNS Energy Compensation Committee granted 43,120 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $45.54 per share. Those awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Return to the Edison Electric Institute Index during the performance period of January 1, 2013 through December 31, 2015. The remaining half had a grant date fair value of $46.23 per share and will be paid out in Common Stock based on cumulative net income for the three-year period ended December 31, 2015. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents, during the performance period, which are paid upon vesting.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded less than $1 million of share-based compensation expense for the three months ended March 31, 2013 and March 31, 2012.

At March 31, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At March 31, 2013, 1 million shares were awarded but not yet issued, including target performance based shares, under the share-based compensation plans.

NOTE 9. FAIR VALUE MEASUREMENTS

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

The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. There were no transfers between Levels 1, 2, or 3 for either reporting period.

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	UNS Energy
	Level 1		Level 2			Level 3			Total
	March 31, 2013
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	15	$	—		$	—		$	15
Restricted Cash Equivalents⁽¹⁾	7		—			—			7
Rabbi Trust Investments to Support the Deferred Compensation and Supplemental Executive Retirement Plan (SERP)⁽²⁾	—		20			—			20
Energy Contracts⁽³⁾	—		5			4			9
Total Assets	22		25			4			51
Liabilities
Energy Contracts⁽³⁾	—		(3		)	(7		)	(10		)
Interest Rate Swaps⁽⁴⁾	—		(9		)	—			(9		)
Total Liabilities	—		(12		)	(7		)	(19		)
Net Total Assets (Liabilities)	$	22	$	13		$	(3	)	$	32



	UNS Energy
	Level 1		Level 2			Level 3			Total
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	20	$	—		$	—		$	20
Restricted Cash Equivalents⁽¹⁾	7		—			—			7
Rabbi Trust Investments to Support the Deferred Compensation and SERP⁽²⁾	—		19			—			19
Energy Contracts⁽³⁾	—		2			5			7
Total Assets	27		21			5			53
Liabilities
Energy Contracts⁽³⁾	—		(7		)	(10		)	(17		)
Interest Rate Swaps⁽⁴⁾	—		(10		)	—			(10		)
Total Liabilities	—		(17		)	(10		)	(27		)
Net Total Assets (Liabilities)	$	27	$	4		$	(5	)	$	26

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	TEP
	Level 1		Level 2			Level 3			Total
	March 31, 2013
	Millions of Dollars
Assets
Restricted Cash Equivalents⁽¹⁾	$	7	$	—		$	—		$	7
Rabbi Trust Investments to Support the Deferred Compensation and SERP⁽²⁾	—		20			—			20
Energy Contracts⁽³⁾	—		2			3			5
Total Assets	7		22			3			32
Liabilities
Energy Contracts⁽³⁾	—		(1		)	(4		)	(5		)
Interest Rate Swaps⁽⁴⁾	—		(9		)	—			(9		)
Total Liabilities	—		(10		)	(4		)	(14		)
Net Total Assets (Liabilities)	$	7	$	12		$	(1	)	$	18



	TEP
	Level 1		Level 2			Level 3			Total
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	1	$	—		$	—		$	1
Restricted Cash Equivalents⁽¹⁾	7		—			—			7
Rabbi Trust Investments to Support the Deferred Compensation and SERP⁽²⁾	—		19			—			19
Energy Contracts⁽³⁾	—		1			2			3
Total Assets	8		20			2			30
Liabilities
Energy Contracts⁽³⁾	—		(3		)	(2		)	(5		)
Interest Rate Swaps⁽⁴⁾	—		(10		)	—			(10		)
Total Liabilities	—		(13		)	(2		)	(15		)
Net Total Assets (Liabilities)	$	8	$	7		$	—		$	15


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


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

⁽³⁾

Energy Contracts include gas swap agreements (Level 2), gas and power options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments and Other Assets on the balance sheets. The valuation techniques are described below. See Note 12.


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

ENERGY CONTRACTS

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange pricing, adjusted for basis differences, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for

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power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.

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

We estimate the fair value of our options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, correlations, interest rates, and forward price curves.

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

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

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



	Fair Value at
	March 31, 2013					Range of
	Assets		Liabilities			Unobservable Input
	Millions of Dollars
Forward Contracts⁽¹⁾	$	2	$	(7	)
Valuation Technique: Market approach
Unobservable Input:
Market price per MWh						$26.00 - $58.91
Option Contracts⁽²⁾	2		—
Valuation Technique: Option model
Unobservable Inputs:
Market Price per MWh						$36.50 - $49.50
Power Volatility						29.3% - 53.6%
Market Price per MMbtu						$3.82 - $4.23
Gas Volatility						27.2% - 28.9%
Level 3 Energy Contracts	$	4	$	(7	)


⁽¹⁾	TEP comprises $1 million of the forward contract assets and $(4) million of the forward contract liabilities.


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

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

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

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	Three Months Ended March 31, 2013
	UNS Energy			TEP
	Millions of Dollars
Balances as of December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	1			(1		)
Settlements	1			—
Balances as of March 31, 2013	$	(3	)	$	(1	)

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



	Three Months Ended March 31, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances as of December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(5		)	1
Other Comprehensive Loss	(1		)	(1		)
Settlements	3			—
Balances as of March 31, 2012	$	(13	)	$	—

Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(2	)	$	—

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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


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


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


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

•

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

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

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		March 31, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		23		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,504		1,599		1,498		1,583
TEP	Level 2	1,223		1,282		1,223		1,271

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

NOTE 10. UNS ENERGY EARNINGS PER SHARE

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

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



	Three Months Ended March 31,
	2013		2012
	Thousands of Dollars
Numerator: Net Income	$	11,345	$	6,476
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,381		37,893
Fully Vested Deferred Stock Units	159		138
Total Weighted Average Common Stock Outstanding – Basic	41,540		38,031
Effect of Dilutive Securities:
Options and Stock Issuable Under Share-Based Compensation Plans	335		290
Total Weighted Average Common Stock Outstanding – Diluted	41,875		38,321

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



	Three Months Ended March 31,
	2013	2012
	Thousands of Shares
Shares from Potential Conversion of Convertible Senior Notes	—	3,340
Stock Options	—	101
Restricted Stock Units	24	—
Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	24	3,441

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

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NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION

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



	UNS Energy
	Three Months Ended March 31,
	2013			2012
	Thousands of Dollars
Net Income	$	11,345		$	6,476
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	36,300			34,984
Amortization Expense	8,289			8,664
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	1,759			1,644
Amortization of Deferred Debt-Related Costs Included in Interest Expense	750			808
Provision for Retail Customer Bad Debts	318			706
Use of RECs for Compliance	3,870			1,414
Deferred Income Taxes	22,078			916
Pension and Retiree Expense	5,696			5,463
Pension and Retiree Funding	(1,734		)	(2,541		)
Share-Based Compensation Expense	722			494
Allowance for Equity Funds Used During Construction	(1,175		)	(850		)
Decrease to Reflect PPFAC/PGA Recovery	(5,368		)	(2,561		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	19,003			27,294
Materials and Fuel Inventory	1,574			(12,720		)
Accounts Payable	(13,458		)	(17,163		)
Income Taxes	(16,028		)	(73		)
Interest Accrued	(9,974		)	(13,191		)
Taxes Other Than Income Taxes	12,534			10,009
Other	4,552			(3,203		)
Net Cash Flows – Operating Activities	$	81,053		$	46,570

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	TEP
	Three Months Ended March 31,
	2013			2012
	Thousands of Dollars
Net Income (Loss)	$	1,478		$	(1,461	)
Adjustments to Reconcile Net Income (Loss)
To Net Cash Flows from Operating Activities
Depreciation Expense	28,558			27,467
Amortization Expense	9,222			9,591
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	1,493			1,248
Amortization of Deferred Debt-Related Costs Included in Interest Expense	601			525
Provision for Retail Customer Bad Debts	246			434
Use of RECs for Compliance	3,540			1,217
Deferred Income Taxes	12,276			(1,600		)
Pension and Retiree Expense	4,970			4,821
Pension and Retiree Funding	(1,676		)	(2,185		)
Share-Based Compensation Expense	575			390
Allowance for Equity Funds Used During Construction	(850		)	(675		)
Decrease to Reflect PPFAC Recovery	(2,360		)	(7,686		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	11,408			17,956
Materials and Fuel Inventory	1,654			(12,660		)
Accounts Payable	(6,094		)	(10,240		)
Income Taxes	(10,877		)	(618		)
Interest Accrued	(6,826		)	(8,004		)
Taxes Other Than Income Taxes	10,068			7,985
Other	1,993			(4,954		)
Net Cash Flows – Operating Activities	$	59,399		$	21,551

Non-Cash Transactions

In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. See Note 4.

In the first quarter of 2012, UNS Energy partially converted $73 million of the previously outstanding $150 million Convertible Senior Notes into Common Stock, resulting in a non-cash transaction.

In March 2012, TEP's redemption of $184 million of tax-exempt bonds resulted in a non-cash transaction.

NOTE 12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

RISKS AND OVERVIEW

We are exposed to energy price risk associated with our gas and purchased power requirements, volumetric risk associated with our seasonal load, and operational risk associated with our generating facilities, transmission, and transportation systems. We reduce our energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Notes 2 and 9.

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and allocate the credit risk adjustment to individual contracts.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.

FINANCIAL IMPACT OF DERIVATIVES

Cash Flow Hedges

UNS Energy and TEP had liabilities related to cash flow hedges of $11 million as of March 31, 2013 and $12 million as of December 31, 2012. A portion of these cash flow hedges relate to TEP's power purchase swap agreement which expires in 2015.

The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 13. The amounts reclassified to earnings are reported in Interest Expense - Long-Term Debt and Interest Expense - Capital Leases in the income statements. The amounts expected to be reclassified to earnings within the next twelve months is estimated to be $4 million.

Regulatory Treatment of Commodity Derivatives

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



	UNS Energy					TEP
	Three Months Ended March 31,
	2013			2012		2013			2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	(9	)	$	8	$	(2	)	$	5

The fair values of commodity derivative assets and liabilities were as follows:



	UNS Energy						TEP
	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012
	Millions of Dollars
Assets	$	9		$	7		$	5		$	4
Liabilities	(8		)	(15		)	(3		)	(4		)
Net Assets (Liabilities)	$	1		$	(8	)	$	2		$	—

Derivative assets are included in Derivative Instruments and Other Assets on the UNS Energy balance sheet and Current Assets - Other and Other Assets on the TEP balance sheet.

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



	UNS Energy				TEP
	Three Months Ended March 31,
	2013		2012		2013		2012
	Millions of Dollars
Realized Losses on Settled Gas Swaps	$	3	$	7	$	1	$	2

At March 31, 2013, UNS Energy and TEP had contracts that will settle through the first quarter of 2016.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

Other Commodity Derivatives

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



	UNS Energy						TEP
	Three Months Ended March 31,
	2013			2012			2013			2012
	Millions of Dollars
Recorded in Wholesale Sales:
Forward Power Sales	$	4		$	5		$	2		$	1
Forward Power Purchases	(5		)	(5		)	(2		)	(2		)
Total Sales and Purchases Not Resulting in Physical Delivery	$	(1	)	$	—		$	—		$	(1	)

Derivatives with Netting Arrangements

The majority of our derivatives contracts include netting arrangements which allow for net payment upon settlement. We present derivatives gross on the balance sheets. The following tables present the balances of derivatives with netting arrangements and the effect if the balances were presented net:



	Gross Amounts Recognized			Gross Amounts of Derivative Instruments Not Offset in the Balance Sheets			Net Amount
	UNS Energy
	March 31, 2013
	Millions of Dollars
Derivative Assets	$	9		$	(9	)	$	—
Derivative Liabilities	(17		)	9			(8		)

	December 31, 2012
Derivative Assets	$	7		$	(7	)	$	—
Derivative Liabilities	(26		)	7			(19		)

	TEP
	March 31, 2013
Derivative Assets	$	5		$	(5	)	$	—
Derivative Liabilities	(12		)	5			(7		)

	December 31, 2012
Derivative Assets	$	4		$	(4	)	$	—
Derivative Liabilities	(14		)	4			(10		)

DERIVATIVE VOLUMES

At March 31, 2013, UNS Energy had gas contracts totaling 19,751 billion British thermal units (GBtu) and power contracts totaling 2,327 Gigawatt-hours (GWh), while TEP had gas contracts totaling 8,774 GBtu and power contracts totaling 990 GWh. At December 31, 2012, UNS Energy had gas contracts totaling 17,851 GBtu and power contracts totaling 2,228 GWh, while TEP had gas contracts totaling 7,958 GBtu and power contracts totaling 820 GWh.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

CREDIT RISK ADJUSTMENT

When the fair value of our derivative contracts is reflected as an asset, the counterparty owes us and this creates credit risk. We also consider the impact of our own credit risk on instruments that are in a net liability position. The impact of counterparty credit risk and our own credit risk on the fair value of derivative asset contracts was less than $0.1 million at March 31, 2013 and at December 31, 2012.

CONCENTRATION OF CREDIT RISK

The following table shows the sum of the fair value of all derivative instruments under contracts with credit risk-related contingent features that are in a net liability position at March 31, 2013. It also shows additional collateral to be posted if credit-risk contingent features are triggered.



	UNS Energy		TEP
	March 31, 2013
	Millions of Dollars
Net Liability Position	$	15	$	3
Additional Collateral to Post if Contingent Features Triggered	15		3

At March 31, 2013, TEP had $12 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities, of which three counterparties composed 52% of the total credit exposure. UNS Electric had $2 million of such credit exposure related to its supply and hedging contracts. At March 31, 2013, UNS Gas had $0.1 million exposure to other counterparties’ creditworthiness.

NOTE 13. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

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



Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Three Months Ended
	March 31, 2013
	Millions of Dollars
Gains and (Losses) on Cash Flow Hedges
Interest Rate Swaps	$	(0.3	)	$	(0.3	)	Interest Expense Long-Term Debt
Interest Rate Swaps	(0.6		)	(0.6		)	Interest Expense Capital Leases
Tax (Expense) Benefit	0.4			0.4
Realized Losses on Cash Flow Hedges, Net of Taxes	(0.5		)	(0.5		)

Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(0.1		)	(0.1		)	Other Expense
Tax (Expense) Benefit	—			—
Amortization, Net of Taxes	(0.1		)	(0.1		)

Total Reclassifications from Other Comprehensive Income for the Period	$	(0.6	)	$	(0.6	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded) - Unaudited

NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT

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

NOTE 15. REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The UNS Energy and TEP condensed consolidated financial statements as of March 31, 2013, and for the three month periods ended March 31, 2013 and 2012, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their reports (dated April 29, 2013) are included on pages 1 and 2. The reports of PricewaterhouseCoopers LLP state that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their reports on the unaudited financial information because neither of those reports is a “report” or a “part” of the registration statements prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

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

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


•	outlook and strategies;


•	operating results during the first quarter of 2013, compared with the same period in 2012;


•	factors affecting our results and outlook;


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


•	dividends; and


•	critical accounting estimates.

Management’s Discussion and Analysis should be read in conjunction with (i) UNS Energy’s and TEP's 2012 Annual Report on Form 10-K and (ii) the Condensed Consolidated Financial Statements that begin on page three of this document. The Condensed Consolidated Financial Statements present the results of operations for the three months ended March 31, 2013 and 2012. Management’s Discussion and Analysis explains the differences between periods for specific line items of the Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

OVERVIEW OF CONSOLIDATED BUSINESS

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

TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of March 31, 2013. TEP generates, transmits, and distributes electricity to approximately 407,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agricultural Improvement and Power District (SRP).

UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated public utility, which generates, transmits, and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties.

UED currently has no significant assets.

Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of March 31, 2013.

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

OUTLOOK AND STRATEGIES

Our financial prospects and outlook are affected by many factors including: the outcome of TEP's pending rate proceeding before the ACC; national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:


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


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


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

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•

Developing a long-term diversification strategy for our generating portfolio. We are evaluating several energy resource options including coal, natural gas, and renewable generating resources. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.


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


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

RESULTS OF OPERATIONS

Contribution by Business Segment

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



	Three Months Ended March 31,
	2013		2012
	Millions of Dollars
TEP	$	1	$	(1	)
UNS Gas	8		5
UNS Electric	2		3
Other Non-Reportable Segments and Adjustments ⁽¹⁾	—		(1		)
Consolidated Net Income	$	11	$	6


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

Executive Overview

First Quarter of 2013 Compared with the First Quarter of 2012

TEP

TEP reported net income of $1 million in the first quarter of 2013 compared with a net loss of $1 million in the first quarter of 2012. The increase in net income in the first quarter of 2013 is attributable to: a $5 million increase in retail margin revenues related to cold weather that contributed to a 4.0% increase in retail sales volumes; partially offset by a $1 million increase in depreciation and amortization expense related to an increase in net utility plant in service; and a $1 million increase in taxes other than income taxes due in part to an increase in property taxes. See Tucson Electric Power Company, Results of Operations, for more information.

UNS Gas

UNS Gas reported net income of $8 million in the first quarter of 2013 compared with net income of $5 million in the first quarter of 2012. The increase in net income is due primarily to: a $3 million increase retail margin revenues related to cold weather that contributed to a 12.2% increase in retail therm sales; and a non-fuel base rate increase that was effective in May 2012. See UNS Gas, Results of Operations, for more information.

UNS Electric

UNS Electric reported net income of $2 million in the first quarter of 2013 compared with net income of $3 million in the first quarter of 2012. The decrease in net income was due in part to increases in depreciation expense and taxes other than income taxes. See UNS Electric, Results of Operations, for more information.

Other Non-Reportable Segments

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

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Operations and Maintenance Expense

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



	Three Months Ended March 31,
	2013		2012
	Millions of Dollars
UNS Energy Base O&M (Non-GAAP)⁽¹⁾	$	69	$	69
Reimbursed Expenses Related to Springerville Units 3 and 4	14		13
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs⁽²⁾	7		12
Total UNS Energy O&M (GAAP)	$	90	$	94

⁽¹⁾

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


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

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

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

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



Balances as of April 17, 2013	Cash and Cash Equivalents		Borrowings under Revolving Credit Facility⁽¹⁾		Amount Available under Revolving Credit Facility
	Millions of Dollars
UNS Energy Stand-Alone	$	1	$	51	$	74
TEP	33		21		179
UNS Gas⁽²⁾	37		—		70
UNS Electric⁽²⁾	13		5		65
Other⁽³⁾	3		N/A		N/A
Total	$	87


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


⁽²⁾	Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both companies cannot exceed $100 million.


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

Dividends from Subsidiaries

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

Short-term Investments

UNS Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update this policy in response to market conditions. As of March 31, 2013, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit.

Access to Revolving Credit Facilities

We have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP Credit Agreement and UNS Gas/UNS Electric Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Gas, and UNS Electric each issue LOCs from time to time to

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provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs for general corporate purposes.

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

UNS Energy Consolidated Cash Flows



	Three months ended March 31,
	2013			2012
	Millions of Dollars
Operating Activities	$	81		$	47
Investing Activities	(75		)	(55		)
Financing Activities	(67		)	7

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

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

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

Operating Activities

In the first three months of 2013, net cash flows from operating activities were $34 million higher than they were in the same period last year. The following items affected the year-over-year change in operating cash flows: an increase in cash receipts from retail and wholesale energy sales (net of fuel and purchased energy costs) due in part to cold winter weather that led to an increase in retail energy sales; a decrease in operations and maintenance costs due in part to fewer scheduled plant maintenance outages and lower customer rebates made under DSM programs; and lower interest paid on debt and capital lease obligations due to a decline in the balance of capital lease obligations.

Investing Activities

Net cash flows used for investing activities increased by $20 million in the first three months of 2013 compared with the same period last year due in part to lower proceeds from investments in Springerville lease debt and an increase in capital expenditures.

Capital Expenditures



	Actual Year-to-Date		Full Year Estimate
	March 31, 2013		2013
	Millions of Dollars
TEP	$	62	$	287
UNS Gas	4		14
UNS Electric	15		40
UNS Energy Consolidated	$	81	$	341

Financing Activities

Net cash flows from financing activities were $74 million lower in the first three months of 2013 compared with the same period last year due to: an increase in scheduled capital lease payments; an increase in dividends paid on common stock; and a decrease in proceeds from borrowings (net of repayments) under revolving credit facilities.

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UNS Credit Agreement

The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. As of March 31, 2013, there was $51 million outstanding at a weighted-average interest rate of 1.95%. The UNS Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UNS Credit Agreement also requires UNS Energy to meet a minimum cash flow to debt service coverage ratio determined on a UNS Energy stand-alone basis. Additionally, UNS Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UNS Credit Agreement, UNS Energy may pay dividends so long as it maintains compliance with the agreement. UNS Energy’s obligations under the agreement are secured by a pledge of the common stock of Millennium, UES, and UED.

As of March 31, 2013, we were in compliance with the terms of the UNS Credit Agreement.

Convertible Senior Notes

In March 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. Between December 2011 and May 2012, holders of approximately $147 million of the Convertible Senior Notes outstanding converted their interests into approximately 4.3 million shares of Common Stock. The remaining $3 million of outstanding Convertible Senior Notes were redeemed at par for cash.

Interest Rate Risk

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

Contractual Obligations

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


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


•	Purchase Power Obligations - We entered into new forward purchase power commitments with minimum payment obligations of $3 million in 2014.

•

RES Performance-based Incentives - We entered into new purchase agreements to purchase the environmental attributes, or Renewable Energy Credits (RECs), from retail customers with solar installations. Payments for these RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals, usually quarterly, based on metered renewable energy production over periods ranging from 9 to 20 years. Our total obligation related to RES PBI payments over future periods increased by $5 million from $68 million on December 31, 2012, to $73 million on March 31, 2013. PBIs are recoverable through the RES tariff. See Note 6.


•	In March 2013, $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.0% and are due in September 2029. Proceeds were used to redeem $91 million of 2008 Pima Bonds bearing interest at a rate of 6.375% with the same maturity date. As a result, our interest obligations decreased by about $2 million per year. See Note 4.


•	In the first quarter 2013, we reduced unrecognized tax benefits by $28 million based on a favorable ruling from the Internal Revenue Service allowing us to deduct, rather than defer and amortize, up-front incentive payments to customers who install renewable energy resources. See Note 5.

Dividends on Common Stock

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



Declaration Date	Record Date	Payment Date	Dividend Amount Per Share of Common Stock
February 25, 2013	March 13, 2013	March 25, 2013	$	0.435

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Income Tax Position

The 2010 Federal Tax Relief Act and the American Taxpayer Relief Act of 2012 include provisions that make qualified property placed in service during 2012 and 2013 eligible for 50% bonus depreciation for tax purposes. In addition, the IRS issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits UNS Energy and TEP otherwise would have received over 20 years. As a result of these provisions, UNS Energy and TEP do not expect to pay any federal or state income taxes through 2015.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

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

First quarter of 2013 compared with the first quarter of 2012

TEP reported net income of $1 million in the first quarter of 2013 compared with a net loss of $1 million in the first quarter of 2012. The following factors affected TEP’s results in the first quarter of 2013:


•	a $5 million increase in retail margin revenues. A 29.0% increase in Heating Degree Days compared with the first quarter of 2012 contributed to a 4.0% increase in retail kilowatt-hour (kWh) sales; and


•	a $2 million decrease in interest expense due to a decline in the balance of capital lease obligations;

partially offset by


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


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

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Utility Sales and Revenues

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



	Three Months Ended March 31,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	793		730		63			8.6	%
Commercial	403		396		7			1.8	%
Industrial	473		469		4			1.0	%
Mining	270		273		(3		)	(1.2	)%
Public Authorities	56		50		6			13.0	%
Total Electric Retail Sales	1,995		1,918		77			4.0	%
Retail Margin Revenues (in Millions):
Residential	$	50	$	46	$	4		8.2	%
Commercial	32		31		1			2.0	%
Industrial	19		20		(1		)	(1.0	)%
Mining	6		6		—			—	%
Public Authorities	3		2		1			12.0	%
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	110		105		5			4.3	%
Fuel and Purchased Power Revenues	64		49		15			31.0	%
RES & DSM Revenues	11		12		(1		)	(9.3	)%
Total Retail Revenues (GAAP)	$	185	$	166	$	19		11.2	%
Average Retail Margin Rate (Cents / kWh):
Residential	6.29		6.31		(0.02		)	(0.3	)%
Commercial	7.77		7.76		0.01			0.1	%
Industrial	4.10		4.18		(0.08		)	(1.9	)%
Mining	2.41		2.38		0.03			1.3	%
Public Authorities	4.94		4.98		(0.04		)	(0.8	)%
Average Retail Margin Revenue	5.51		5.50		0.01			0.2	%
Average Fuel and Purchased Power Revenue	3.22		2.56		0.66			25.8	%
Average RES & DSM Revenue	0.54		0.62		(0.08		)	(12.9	)%
Total Average Retail Revenue	9.27		8.68		0.59			6.8	%

Weather Data:
Heating Degree Days
Three Months Ended March 31,	953		739		214			29.0	%
10-Year Average	821		795		NM			NM
Wholesale Energy Market Indicators:
Power Prices ($ / MWh)⁽³⁾	$	32.00	$	24.96	$	7.04		28.2	%
Natural Gas Prices ($ / MMBtu) ⁽⁴⁾	3.41		2.39		1.02			42.7	%


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

⁽²⁾

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


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


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

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Residential

Residential kWh sales were 8.6% higher in the first quarter of 2013 than they were during the same period last year, leading to an increase in residential margin revenues of 8.2%, or $4 million. Residential use per customer increased by 7.8% due primarily to a 29.0% increase in Heating Degree Days compared with the same period last year. The average number of residential customers grew by 0.6% in the first quarter of 2013 compared with the same period last year.

Commercial

Commercial kWh sales increased by 1.8% compared with the first quarter of 2012, leading to an increase in commercial margin revenues of 2.0%, or $1 million. Commercial use per customer increased by 1.8% due in part to a 29.0% increase in Heating Degree Days compared with the same period last year. The average number of commercial customers was the same in the first quarter of 2013 when compared with the same period last year.

Industrial

Industrial kWh sales increased by 1.0% compared with the first quarter of 2012, while industrial margin revenues decreased by 1.0% when compared with the same period in 2012. The decline in industrial retail margins resulted from a change in usage patterns by certain industrial customers that reduced their demand charges paid to TEP.

Mining

Mining kWh sales decreased by 1.2% compared with the first quarter of 2012 due in part to a temporary decrease in production by one of TEP's customers. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

Wholesale Sales and Transmission Revenues



	Three Months Ended March 31,
	2013		2012
	Millions of Dollars
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)⁽¹⁾	$	2	$	2
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues	6		5
Total Long-Term Wholesale Revenues	8		7
Transmission Revenues	4		4
Short-Term Wholesale Revenues	22		19
Electric Wholesale Sales (GAAP)	$	34	$	30

⁽¹⁾

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

Long-Term Wholesale Margin Revenues in the first quarter of 2013 were the same when compared with the first quarter of 2012. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project, below, for more information.

Short-Term Wholesale Revenues

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

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Other Revenues



	Three Months Ended March 31,
	2013		2012
	Millions of Dollars
Revenue related to Springerville Units 3 and 4⁽¹⁾	$	21	$	21
Other Revenue	7		7
Total Other Revenue	$	28	$	28

⁽¹⁾ Represents revenues and reimbursements from Tri-State and SRP, owners of Springerville Units 3 and 4, respectively,

to TEP related to the operation of these plants.

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

Operating Expenses

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for the first quarters of 2013 and 2012 are detailed below:



	Generation and Purchased Power				Fuel and Purchased Power Expense
	Three Months Ended March 31,
	2013		2012		2013			2012
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	2,471		2,337		$	71		$	57
Gas-Fired Generation	186		290		8			11
Renewable Generation	16		15		—			—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		2			2
Total Fuel	2,673		2,642		81			70
Total Purchased Power	428		446		19			14
Transmission	—		—		1			1
Decrease to Reflect PPFAC Recovery Treatment	—		—		(3		)	(8		)
Total Resources	3,101		3,088		$	98		$	77
Less Line Losses and Company Use	(175	)	(194	)
Total Energy Sold	2,926		2,894

Generation

Total generating output increased during the first quarter of 2013 compared with the same period last year due to higher retail kWh sales. Coal-fired generation increased by 5.7% in the first quarter due in part to the use of coal to fuel Sundt Generating Station (Sundt) Unit 4 instead of natural gas.

Purchased Power

Purchased power volumes decreased in the first quarter of 2013 compared with the same period last year due in part to higher output from TEP's generating facilities.

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



	Three Months Ended March 31,
	2013	2012
	cents per kWh
Coal	2.87	2.45
Gas	4.36	3.70
Purchased Power	4.42	3.05
All Sources	3.44	2.92

O&M

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



	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Base O&M (Non-GAAP)⁽¹⁾	$	60		$	60
O&M Recorded in Other Expense	(2		)	(1		)
Reimbursed Expenses Related to Springerville Units 3 and 4	14			13
Expenses Related to Customer Funded Renewable Energy and DSM Programs⁽²⁾	6			10
Total O&M (GAAP)	$	78		$	82


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


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

FACTORS AFFECTING RESULTS OF OPERATIONS

2012 TEP Rate Case

In February 2013, TEP, ACC Staff, and other parties to TEP's pending rate case proceeding entered into a settlement agreement (2013 Settlement Agreement). The 2013 Settlement Agreement requires the approval of the ACC before new rates can become effective.

The terms of the 2013 Settlement Agreement include, but are not limited to:


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


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


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


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


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


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

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The 2013 Settlement Agreement also includes cost adjustment mechanisms, an energy efficiency resource plan and modifications to TEP's PPFAC, which are described below.

Lost Fixed Cost Recovery Mechanism

A Lost Fixed Cost Recovery mechanism (LFCR) would allow TEP to recover certain non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to compliance with the ACC's Electric EE Standards and distributed generation requirements under the RES. The LFCR rate would be adjusted annually and be subject to ACC approval and a year-over-year cap of 1% of TEP's total retail revenues.

Environmental Compliance Adjustor

An Environmental Compliance Adjustor (ECA) mechanism would allow TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA would be adjusted annually to recover environmental compliance costs, subject to a cap equal to 0.25% of TEP's total retail revenues.

Energy Efficiency Resource Plan

The Energy Efficiency Resource Plan (EERP) would allow TEP to invest in cost-effective energy efficiency programs approved by the ACC. Investments under the EERP would be considered regulatory assets and amortized over five-years. If certain thresholds are met as established in the EE implementation plans and approved by the ACC, TEP would recover its costs associated with the EERP, including a return on and a return of its investments, through TEP's existing demand-side management surcharge.

Purchased Power and Fuel Adjustment Clause

A new PPFAC rate, which includes a one-time reduction of approximately $3 million related to sulfur credits and a $9.7 million deferral of certain costs, will be effective at the same time new Base Rates are approved by the ACC. TEP's existing PPFAC mechanism will continue with certain modifications, including the recovery of the following costs and/or credits: lime costs; sulfur credits; broker fees; and 100% of the proceeds from the sale of SO₂ allowances.

Procedural Schedule

Hearings before the ACC administrative law judge assigned to TEP's rate case concluded in March 2013. The judge is expected to issue a recommended opinion and order during the second quarter of 2013. That recommendation is then subject to approval by the ACC.

The parties to the 2013 Settlement Agreement agreed to ask the ACC (1) to find that the terms and conditions of the 2013 Settlement Agreement are just and reasonable and in the public interest, along with any and all other necessary findings, and (2) to approve the 2013 Settlement Agreement such that it and the rates contained therein may become effective on July 1, 2013.

TEP cannot predict if the 2013 Settlement Agreement will be approved or modified by the ACC.

Purchased Power and Fuel Adjustment Clause

In March 2012, the ACC approved a PPFAC rate of 0.77 cents per kWh effective April 2012 to recover $77 million of under-collected fuel and purchased power costs. At March 31, 2013, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $18 million.

The 2013 Settlement Agreement includes certain modifications to TEP's PPFAC. In February 2013, TEP filed a request with the ACC to defer the effective date of resetting the PPFAC until the effective date of new rates in TEP's pending rate case. This request is consistent with a provision of the 2013 Settlement Agreement. TEP cannot predict if or when the ACC will respond to its request. See 2012 TEP Rate Case, Purchase Power and Fuel Adjustment Clause, above, for more information.

Springerville Units 3 and 4

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

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

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	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Other Revenues	$	21		$	21
Fuel Expense	(2		)	(2		)
O&M Expense	(14		)	(13		)
Total Pre-Tax Income	$	5		$	6

Pension and Retiree Benefit Expense

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



	Three Months Ended March 31,
	2013		2012
	Millions of Dollars
Pension Expense Charged to O&M	$	3	$	3
Retiree Benefit Expense Charged to O&M	1		1
Total	$	4	$	4

Long-Term Wholesale Sales

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

Salt River Project

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

Navajo Tribal Utility Authority

TEP serves the portion of NTUA’s load that is not served from NTUA’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh. The power sold to NTUA is at a fixed price except for 50% of the MWh sales from June to September, which are based on the Dow Jones Palo Verde Market Index. Similar to 2012, we expect approximately 13% of the total energy sold to NTUA in 2013 will be priced based on the Dow Jones Palo Verde Market Index. The NTUA contract expires in December 2015.

Long-Term Wholesale Margin and Sensitivity

TEP’s margin on long-term wholesale sales was $2 million during the first three months of 2013 and 2012.

As of April 17, 2013, the average forward price of on-peak power on the Dow Jones Palo Verde Market Index for the remainder of calendar year 2013 was $40 per MWh; the average price of on-peak power during the first quarter of 2013 was $32 per MWh. A change of $5 per MWh in the on-peak market price of power on the Dow Jones Palo Verde Market Index for the balance of the year would change 2013 pre-tax income related to the SRP contract by approximately $2 million.

Electric Energy Efficiency Standards

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

New and existing DSM programs, direct load control programs, and energy efficient building codes are acceptable means to meet the Electric EE Standards as set forth by the ACC. The Electric EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP's programs, and the rates charged to customers for such programs, are subject to annual review and approval by the ACC.

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A proposed settlement agreement in TEP's pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. See 2012 TEP Rate Case, Energy Efficiency Resource Plan, above.

Decoupling

In 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona's Electric EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring utility rates to separate the recovery of fixed costs from the level of energy consumed. The policy statement allows affected utilities to file rate decoupling proposals in their next general rate case. A proposed settlement agreement in TEP's pending rate case proceeding includes a partial decoupling mechanism. See 2012 TEP Rate Case, Lost Fixed Cost Recovery Mechanism, above.

Renewable Energy Standard and Tariff

In January 2013, the ACC approved TEP's 2013 RES implementation plan. Under the plan, TEP expects to collect approximately $36 million from retail customers during 2013. The plan includes an investment of $28 million in 2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $4 million pre-tax in 2013 on solar investments made in 2010, 2011, and 2012. TEP expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales.

Competition

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

Retail Electric Competition Rules

In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004. In 2008, the ACC opened an administrative proceeding to address the Rules but has since taken no action. During 2012, a small number of companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP's service territory as an ESP. Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP's retail customers to use an alternative ESP. We cannot predict what changes, if any, the ACC will make to the Rules or if the ACC will grant a CC&N to an ESP.

Sales to Mining Customers

Copper prices have triggered an increase in mining activity at the copper mines operating in TEP's service area. TEP's mining customers have indicated they are taking initial steps to increase production either through expansion of their current mining operations or by the re-opening of non-operational mine sites. If efforts to increase production are successful, TEP's mining load could increase by up to 100 MW over the next several years. The market price for copper and the ability to obtain necessary permits could affect the mining industry's expansion plans.

In addition to the mining customers that TEP currently serves, Augusta Resources Corporation filed a plan of operations with the United States Forest Service in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona. The Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line for the construction and ongoing operation of the mine. A certificate of environmental compatibility (CEC) from the state line siting committee was approved in 2011 for the 138 kV transmission line. In 2012, the ACC finalized the CEC. If the Rosemont Copper Mine were to reach full production, it would be expected to become TEP's largest retail customer, with TEP serving approximately 90 MW of the mine's total estimated load of approximately 100 MW.

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

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Interest Rates

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under its revolving credit facility. At March 31, 2013, TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds is 10% on $37 million of bonds and 20% on the other $178 million. During the first three months of 2013, the average rates paid ranged from 0.08% to 0.15%. At April 17, 2013, the average rate on the debt was 0.23%.

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

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

Fair Value Measurements

TEP’s income statement exposure to energy price risk is mitigated as TEP reports the change in fair value of energy contract derivatives as either a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement. See Note 9.

LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

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



	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	59		$	22
Amounts from Statements of Cash Flows:
Less: Capital Expenditures	(62		)	(67		)
Net Cash Flows after Capital Expenditures (Non-GAAP)⁽¹⁾	(3		)	(45		)
Amounts From Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations	(81		)	(74		)
Plus: Proceeds from Investment in Lease Debt	9			19
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)⁽¹⁾	$	(75	)	$	(100	)



	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	59		$	22
Net Cash Flows – Investing Activities (GAAP)	(55		)	(43		)
Net Cash Flows – Financing Activities (GAAP)	(62		)	13
Net Cash Flows after Capital Expenditures (Non-GAAP)⁽¹⁾	(3		)	(45		)
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)⁽¹⁾	(75		)	(100		)

⁽¹⁾

Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows—Operating Activities, which is determined in accordance with GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make

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required payments on capital lease obligations, and pay dividends to UNS Energy before consideration of financing activities.

Liquidity Outlook

During 2013, TEP expects to generate sufficient operating cash flows to fund the majority of its capital expenditures. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to assist in funding its business activities.

Operating Activities

In the first three months of 2013, net cash flows from operating activities were $37 million higher than in the first three months of 2012 due primarily to:


•	a $19 million increase in cash receipts from retail and wholesale energy sales (net of fuel and purchased energy costs) due in part to cold winter weather that led to an increase in retail sales volumes compared with the first three months of 2012;


•	a $16 million decrease in O&M costs and wages paid, due in part to fewer scheduled generating plant outages and lower customer rebates under DSM programs; and


•	a $3 million decrease in capital lease interest paid due to a decline in capital lease obligation balances.

Investing Activities

Net cash flows used for investing activities increased by $12 million in the first three months of 2013 compared with the same period last year due primarily to lower proceeds from the return of investment in Springerville lease debt.

TEP’s capital expenditures were $62 million in the first three months of 2013 compared with $67 million in the same period last year. TEP’s estimated capital expenditures for 2013 are $287 million.

Financing Activities

In the first three months of 2013, net cash from financing activities was $75 million lower than in the same period in 2012 due to a $75 million decrease in borrowings (net of repayments) made under TEP’s Revolving Credit Facility.

TEP Credit Agreement

The TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $186 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016 and is secured by $386 million of Mortgage Bonds. As of March 31, 2013, there was $20 million of outstanding borrowings and $1 million of LOCs issued under the TEP Revolving Credit Facility.

The TEP Credit Agreement contains restrictions on liens, mergers, and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UNS Energy. As of March 31, 2013, TEP was in compliance with the terms of the TEP Credit Agreement.

2010 TEP Reimbursement Agreement

In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt pollution control bonds that were issued on behalf of TEP in December 2010.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of March 31, 2013, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

2013 Bond Issuances and Redemptions

In March 2013, approximately $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029 and may be redeemed at par on or after March 1, 2023. In April 2013, the proceeds of the bond issuance were used to redeem approximately $91 million of unsecured tax-exempt bonds with an interest rate of 6.375% and a maturity date of September 2029. See Note 4.

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Capital Lease Obligations

As of March 31, 2013, TEP had $275 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease obligations:



	Capital Lease Obligation Balance As Of
Capital Leases	March 31, 2013		Expiration	Renewal/Purchase Option
	Millions of Dollars
Springerville Unit 1⁽¹⁾	$	133	2015	Fair market value purchase option of $159 million⁽²⁾
Springerville Coal Handling Facilities Lease	43		2015	Fixed price purchase option of $120 million⁽³⁾
Springerville Common Facilities⁽⁴⁾	99		2017 and 2021	Fixed price purchase option of $106 million⁽³⁾
Total Capital Lease Obligations	$	275


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


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

⁽³⁾

TEP agreed with Tri-State, the lessee of Springerville Unit 3 and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri State will then be obligated to either 1) buy a portion of these facilities; or 2) continue making payments to TEP for the use of these facilities.


⁽⁴⁾	The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities.

TEP's capital lease obligation balances decline over time due to the normal capital lease payments made by TEP. See Note 6 for more information about the fixed purchase price amounts.

Income Tax Position

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

Contractual Obligations

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


•	TEP entered into new forward purchase power commitments that will settle through December 2014. Some of these contracts are at fixed prices per MWh and others are indexed to natural gas prices. Based on projected market prices as of March 31, 2013, TEP's estimated minimum payment obligations for these additional purchases are $2 million in 2014.

•

TEP is contractually obligated to retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In the first quarter of 2013, TEP's total obligation for RES PBIs increased by $4 million dollars from $62 million on December 31, 2012, to $66 million on March 31, 2013. TEP will make required payments over periods ranging from 9 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 6.

•

In March 2013, $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.0% and are due in September 2029. Proceeds were used to redeem $91 million of 2008 Pima Bonds bearing interest at a rate of 6.375% with the same maturity date. As a result, TEP's interest obligations decreased by about $2 million per year. See Note 4.


•	In the first quarter of 2013, TEP reduced unrecognized tax benefits by $22 million based on a favorable ruling from the Internal Revenue Service allowing us to deduct, rather than defer and amortize, up-front incentive payments to customers who install renewable energy resources. See Note 5.

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Dividends on Common Stock

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement, and certain financial covenants. As of March 31, 2013, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement.

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

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported net income of $8 million in the first quarter of 2013 compared with net income of $5 million in the first quarter of 2012. The increase in net income is due primarily to: cold weather, which contributed to a 12.2% increase in retail therm sales; and a non-fuel base rate increase that was effective in May 2012.

The table below provides summary financial information for UNS Gas:



	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Gas Revenues	$	51		$	51
Other Revenues	1			2
Total Operating Revenues	52			53
Purchased Gas Expense	30			29
Increase (Decrease) to Reflect PGA Recovery Treatment	(1		)	3
O&M	6			7
Depreciation and Amortization	2			2
Taxes Other Than Income Taxes	1			1
Total Other Operating Expenses	38			42
Operating Income	14			11
Interest Expense	2			2
Income Tax Expense	4			4
Net Income	$	8		$	5

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



	Three Months Ended March 31,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Gas Retail Sales, Therms (in Millions):
Residential	35		31		4			13.4	%
Commercial	11		10		1			8.8	%
Industrial	1		1		—			19.1	%
Public Authorities	3		3		—			10.2	%
Total Gas Retail Sales	50		45		5			12.2	%
Negotiated Sales Program (NSP)	7		7		—			(0.6	)%
Total Gas Sales	57		52		5			10.5	%
Retail Margin Revenues (in Millions):
Residential	$	16	$	14	$	2		13.7	%
Commercial	4		3		1			14.3	%
Public Authorities	1		1		—			11.1	%
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	21		18		3			13.7	%
Transport and NSP	4		4		—			16.2	%
Retail Fuel Revenues	26		29		(3		)	(8.1	)%
Total Gas Revenues (GAAP)	$	51	$	51	$	—		2.0	%
Weather Data:
Heating Degree Days
Three Months Ended March 31,	2,188		2,013		175			8.7	%
10-Year Average	2,096		2,103		NM			NM


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

⁽²⁾

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

Retail therm sales during the first quarter of 2013 increased by 12.2% due in part to an 8.7% increase in Heating Degree Days. The increase in retail therm sales, as well as a Base Rate increase implemented in May 2012, contributed to an increase in retail margin revenues of 13.7%, or $3 million, compared with the first quarter of 2012.

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

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

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

Rates

2012 UNS Gas Rate Order

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

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

Purchased Gas Adjustor

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

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

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

In April 2012, the ACC approved the temporary PGA surcredit adjustment of 4.5 cents per therm which became effective on May 1, 2012, and will continue through April 2014 or until the bank balance reaches zero. The credit adjustment over this period is expected to return approximately $10 million of over-collected PGA costs to customers. At March 31, 2013, the PGA bank balance was over-collected by $13 million on a billed-to-customer basis.

Gas Energy Efficiency Standards

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

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

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

Fair Value Measurements

UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 9.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

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

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Cash Flows and Capital Expenditures

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



	Three months ended March 31,
	2013			2012
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	13		$	15
Investing Activities	(4		)	(3		)
Financing Activities	(10		)	(10		)
Net Increase/(Decrease) in Cash	(1		)	2
Beginning Cash	31			38
Ending Cash	$	30		$	40

UNS Gas' operating cash flows during the first three months of 2013 were $2 million lower than the same period last year due in part to higher amounts of gas purchased as a result of increased demand from a cold winter. Cash used for investing activities was higher by $1 million due to similar increase in capital expenditures compared with last year.

UNS Gas/UNS Electric Revolver

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

UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver. As of March 31, 2013, UNS Gas had no outstanding borrowings or LOCs under the UNS Gas/UNS Electric Revolver.

The UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. As of March 31, 2013, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.

Interest Rate Risk

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

Contractual Obligations

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

Dividends on Common Stock

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

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (i) no default or event of default exists, and (ii) it could incur additional debt under the debt incurrence test. As of March 31, 2013, UNS Gas was in compliance with the terms of its note purchase agreement.

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UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $2 million in the first quarter of 2013 compared with $3 million in the same period last year. Like TEP, UNS Electric’s operations are generally seasonal in nature, with peak energy demand occurring in the summer months. The table below provides summary financial information for UNS Electric:



	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Retail Electric Revenues	$	36		$	39
Wholesale Electric Revenues	1			4
Other Revenues	—			1
Total Operating Revenues	37			44
Purchased Energy Expense	17			18
Fuel Expense	1			1
Transmission Expense	3			2
Increase (Decrease) to Reflect PPFAC Recovery	(2		)	2
O&M	7			8
Depreciation and Amortization Expense	5			5
Taxes Other Than Income Taxes	1			1
Total Other Operating Expenses	32			37
Operating Income	5			7
Interest Expense	1			2
Income Tax Expense	2			2
Net Income	$	2		$	3

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



	Three Months Ended March 31,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Electric Retail Sales, kWh (in Millions):
Residential	190		171		19			11.4	%
Commercial	128		131		(3		)	(2.6	)%
Industrial	42		53		(11		)	(20.5	)%
Mining	13		28		(15		)	(52.2	)%
Public Authorities	1		—		1			29.1	%
Total Electric Retail Sales	374		383		(9		)	(2.4	)%

Retail Margin Revenues (in Millions):
Residential	$	7	$	7	$	—		10.6	%
Commercial	6		6		—			(1.6	)%
Industrial	2		2		—			(13.0	)%
Mining	2		2		—			(17.6	)%
Public Authorities	—		—		—			—
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	17		17		—			—	%
Fuel and Purchased Power Revenues	17		19		(2		)	(10.4	)%
RES & DSM Revenues	2		3		(1		)	(39.3	)%
Total Retail Revenues (GAAP)	$	36	$	39	$	(3	)	(7.9	)%
Weather Data:
Heating Degree Days
Three Months Ended March 31,	1,160		1,015		145			14.3	%
10-Year Average	1,102		1,114		NM			NM


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

⁽²⁾

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

Total retail kWh sales in the first quarter of 2013 decreased by 2.4% compared with the same period last year. Sales volumes to mining customers decreased by 52.2% in the first quarter of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Total Retail Margin Revenues in the first quarter of 2013 were similar to the level in the first quarter of 2012. See Factors Affecting Results of Operations, Mining Customer, below.

FACTORS AFFECTING RESULTS OF OPERATIONS

2012 UNS Electric Rate Case

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

The key provisions of UNS Electric's rate request include:


•	an increase in non-fuel retail Base Rates of $7.5 million, or 4.6%, over adjusted test year revenues;


•	an original cost rate base of approximately $217 million, which includes approximately $13 million of post test year adjustments for utility plant that is expected to be in service by June 30, 2013;


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

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•	a cost of long-term debt of 5.97% and return on equity of 10.50%.

Lost Fixed Cost Recovery Mechanism

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

Transmission Cost Adjustment Mechanism

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

Energy Efficiency Resource Plan

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

UNS Electric requested new rates be effective no later than January 1, 2014. We cannot predict the outcome of this proceeding or whether UNS Electric's rate request will be adopted by the ACC in whole or in part.

Renewable Energy Standard and Tariff

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

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

Electric Energy Efficiency Standards

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

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

Retail Electric Competition Rules

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

Competition

New technological developments and the implementation of Electric EE Standards may reduce energy consumption by UNS Electric's retail customers. UNS Electric's customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on UNS Electric's services.

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Large Customers

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

Interest Rates

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

Fair Value Measurements

UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 9.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric expects operating cash flows to fund most of its construction expenditures during 2013. Additional sources of funding capital expenditures, if needed, could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.

Cash Flows and Capital Expenditures

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



	Three Months Ended March 31,
	2013			2012
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	8		$	13
Investing Activities	(16		)	(9		)
Financing Activities	7			—
Net Increase/(Decrease) in Cash	(1		)	4
Beginning Cash	8			5
Ending Cash	$	7		$	9

Operating Activities

Cash provided by operating activities decreased by $5 million in the first three months of 2013 compared with the same period in 2012 due to: a $2 million decrease in cash receipts from electric sales (net of fuel and purchased energy costs paid); and a $3 million increase in income taxes paid (net of income tax refunds received) due primarily to true-up payments related to estimated income tax payments made in 2012.

Investing Activities

UNS Electric had capital expenditures of $15 million in the first three months of 2013 compared with $9 million in the same period in 2012. UNS Electric estimates total capital expenditures in 2013 of $40 million.

Financing Activities

Cash provided by financing activities at UNS Electric in the first three months of 2013 increased by $7 million when compared with the same period in 2012. Financing activities in 2013 included $5 million of borrowings under its revolving credit facility and a $2 million receipt related to a contribution in aid of construction from a large customer.

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UNS Gas/UNS Electric Revolver

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

UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. As of March 31, 2013, UNS Electric had $5 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Gas/UNS Electric Revolver.

Contractual Obligations

In 2013, UNS Electric entered into new forward purchase power commitments that will settle through December 2014 at fixed prices per MWh. UNS Electric’s estimated minimum payment obligations for these purchases are $1 million in 2014.

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

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

Dividends on Common Stock

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

The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (i) no default or event of default exists, and (ii) it could incur additional debt under the debt incurrence test. As of March 31, 2013, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Gas/UNS Electric Revolver.

OTHER NON-REPORTABLE BUSINESS SEGMENTS

RESULTS OF OPERATIONS

The table below summarizes the net loss for the other non-reportable segments:



	Three Months Ended March 31,
	2013		2012
	Millions of Dollars
Millennium	$	—	$	1
Other⁽¹⁾	—		(2		)
Total Other Net Income (Loss)	$	—	$	(1	)


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

UNS Energy Parent Company

UNS Energy parent company expenses primarily include interest expense (net of tax) related to the Convertible Senior Notes and the UNS Credit Agreement. All of the Convertible Senior Notes were either converted to Common Stock or redeemed for cash during the first six months of 2012. See UNS Energy, Liquidity and Capital Resources, Convertible Senior Notes, for more information.

FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

At March 31, 2013, Millennium had assets of $7 million including a cash balance of $4 million.

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CRITICAL ACCOUNTING ESTIMATES

There have been no significant changes in our accounting policies from those disclosed in our 2012 Annual Report on Form 10-K.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

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

PART II – OTHER INFORMATION

ITEM 1. – LEGAL PROCEEDINGS

See the legal proceedings described in Item 3. – Legal Proceedings in our 2012 Annual Report on Form 10-K and in Note 6 and in Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 6 and Item 2 are incorporated herein by reference.

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Springerville Unit 1 Appraisal

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

On April 26, 2012, TEP filed a petition to confirm the appraisal in the United States District Court for the District of Arizona naming the owner participants (Daimler Capital Services LLC, LDVFI TEP LLC, Alterna Springerville LLC, MWR Capital Inc., and Pacific Harbor Capital Inc.) and the owner trustee and co-trustee (Wilmington Trust Company and William J. Wade) as respondents. The petition states that TEP filed the petition since neither the owner participants nor the owner trustee and co-trustee have acknowledged that the purchase price determined by the appraisal procedure in December 2011 is final and binding and that TEP seeks an order from the court confirming the appraisal as an arbitration award under the Federal Arbitration Act (FAA).

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

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

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

ITEM 1A. – RISK FACTORS

The business and financial results of UNS Energy and TEP are subject to numerous risks and uncertainties. There are no significant changes to the risks and uncertainties reported in our 2012 Annual Report on Form 10-K.

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

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

ITEM 3. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2012, other than the following:

Commodity Price Risk—TEP

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

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ITEM 4. – CONTROLS AND PROCEDURES

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

While UNS Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UNS Energy’s or TEP’s internal control over financial reporting during the first quarter of 2013 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.

ITEM 5. – OTHER INFORMATION

Ratio of Earnings to Fixed Charges

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



	Three Months Ended March 31, 2013	Twelve Months Ended March 31, 2013
UNS Energy	1.754	2.457
TEP	1.129	2.216

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

Environmental Matters

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



Generating Station	Estimated Annual O&M Expense		Estimated Capital Expenditures		Regulation (Compliance Date)	Upgrades
	Millions of Dollars
San Juan Unit 1	$	6	$	25	Regional Haze/BART (2016)	SNCRs⁽¹⁾
Navajo Units 1-3	3		86		MATS (2015) Regional Haze/BART (2023)	Mercury Controls; SCRs; Baghouses
Four Corners Units 4 & 5	3		36		MATS (2015) Regional Haze/BART (2018)	Mercury Controls; SCRs
Springerville Units 1 & 2	3		5		MATS (2015)	Mercury Controls

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

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



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

⁽¹⁾As of March 31, 2013, TEP owned a 14% undivided interest in Springerville Unit 1 and leased the remaining 86%.

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

For more information on TEP's environmental matters, please see Note 6.

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.




		UNS ENERGY CORPORATION
		(Registrant)

Date:	April 29, 2013	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer

		TUCSON ELECTRIC POWER COMPANY
		(Registrant)

Date:	April 29, 2013	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer

EXHIBIT INDEX




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

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

15(a)	—	Letter regarding unaudited interim financial information – UNS Energy.

15(b)	—	Letter regarding unaudited interim financial information – TEP.

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

31(b)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Kevin P. Larson.

31(c)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Paul J. Bonavia.

31(d)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Kevin P. Larson.

**32(a)	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) – UNS Energy.

**32(b)	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) – TEP.

***101	—	The following materials from UNS Energy Corporation’s and Tucson Electric Power Company’s Quarterly Report on Form 10-Q for the three and nine-month periods ended September 30, 2012, formatted in XBRL (Extensible Business Reporting Language):


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


(b)	Notes to Condensed Consolidated Financial Statements.

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

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