TEP & UNS 10Q 9.30.2013

10-Q 1 tepuns10q9302013.htm 10-Q TEP & UNS 10Q 9.30.2013

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 September 30, 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 October 25, 2013, 41,537,582 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of October 25, 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 – FINANCIAL INFORMATION
Item 1. – Financial Statements	3
UNS Energy Corporation	3
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	4
Condensed Consolidated Statements of Cash Flows	5
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statement of Changes in Stockholders’ Equity	8
Tucson Electric Power Company	9
Condensed Consolidated Statements of Income	9
Condensed Consolidated Statements of Comprehensive Income	10
Condensed Consolidated Statements of Cash Flows	11
Condensed Consolidated Balance Sheets	12
Condensed Consolidated Statement of Changes in Stockholder’s Equity	14
Notes to Condensed Consolidated Financial Statements - Unaudited	15
Note 1. Financial Statement Presentation	15
Note 2. Regulatory Matters	16
Note 3. Business Segments	18
Note 4. Commitments, Contingencies, and Environmental Matters	19
Note 5. Debt, Credit Facilities, and Capital Lease Obligations	24
Note 6. Income Taxes	25
Note 7. Employee Benefit Plans	26
Note 8. Share-Based Compensation Plans	26
Note 9. UNS Energy Earnings Per Share	27
Note 10. Supplemental Cash Flow Information	29
Note 11. Fair Value Measurements and Derivative Instruments	30
Note 12. Changes in Accumulated Other Comprehensive Income by Component	37
Note 13. Potential Purchase of Gas-Fired Generation Facility	38
Note 14. Recently Issued Accounting Pronouncement	38
Note 15. Review by Independent Registered Public Accounting Firm	38
Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
UNS Energy Corporation	39
Overview of Consolidated Business	39
Outlook and Strategies	39
Results of Operations	40
Liquidity and Capital Resources	42
Tucson Electric Power Company	45
Results of Operations	45
Factors Affecting Results of Operations	52
Liquidity and Capital Resources	57
UNS Gas	61
Results of Operations	61
Factors Affecting Results of Operations	63

iii



Liquidity and Capital Resources	64
UNS Electric	65
Results of Operations	65
Factors Affecting Results of Operations	67
Liquidity and Capital Resources	69
Critical Accounting Estimates	70
Recently Issued Accounting Pronouncement	71
Safe Harbor for Forward-Looking Statements	71
Item 3. – Quantitative and Qualitative Disclosures about Market Risk	71
Item 4. – Controls and Procedures	72

PART II – OTHER INFORMATION
Item 1. – Legal Proceedings	72
Item 1A. – Risk Factors	73
Item 5. – Other Information	73
Ratio of Earnings to Fixed Charges	73
Environmental Matters	73
Item 6. Exhibits	74

Signatures	75
Exhibit Index	76

DEFINITIONS

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




1992 Mortgage		TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York Mellon, successor trustee, as supplemented
2010 TEP Reimbursement Agreement		Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2010 UNS Electric Rate Order		A rate order issued by the ACC resulting in a new rate structure for UNS Electric, effective September 1, 2010
2013 TEP Rate Order		A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013
2013 UNS Electric Settlement Agreement		A rate settlement agreement entered into by UNS Electric and various other parties
ACC		Arizona Corporation Commission
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
BLM		Bureau of Land Management
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
Entegra		Entegra Power Group LLC
EPA		Environmental Protection Agency
EPS		Earnings Per Share
ESP		Electric Service Providers
FAA		Federal Arbitration Act
FASB		Financial Accounting Standards Board
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)
Gila River Unit 3		Unit 3 of the Gila River Generating Station



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
NMED		New Mexico Environmental Department
NSP		Negotiated Sales Program. A program in which UNS Gas sells natural gas to some of its large transportation customers.
NTUA		Navajo Tribal Utility Authority
NOx		Nitrogen Oxide
O&M		Operations and Maintenance
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 9 to 20 years
PGA		Purchased Gas Adjustor, a Retail Rate mechanism designed to recover the cost of gas purchased for retail gas customers
PNM		Public Service Company of New Mexico
PPA		Power Purchase Agreement
PPFAC		Purchased Power and Fuel Adjustment Clause
PSD		Prevention of Significant Deterioration
REC		Renewable Energy Credit
RES		Renewable Energy Standard
Retail Margin Revenues		A non-GAAP financial measure that demonstrates the underlying revenue trend and performance of our core utility businesses
Regional Haze Rules		Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
Retail Rates		Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service
Rules		Retail Electric Competition Rules established by the ACC in 1999
San Juan		San Juan Generating Station
SCR		Selective Catalytic Reduction
SEC		Securities and Exchange Commission
SERP		Supplemental Executive Retirement Plan
SJCC		San Juan Coal Company
SNCR		Selective Non-Catalytic Reduction



SO2		Sulfur Dioxide
Springerville		Springerville Generating Station
Springerville Common Facilities		Facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities Leases		Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1		Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases		Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2		Unit 2 of the Springerville Generating Station
Springerville Unit 3		Unit 3 of the Springerville Generating Station
Springerville Unit 4		Unit 4 of the Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sulfur Credits		Credits applied to the fuel invoice by the supplier when the sulfur content of delivered coal exceeds contractual levels
Sundt		H. Wilson Sundt Generating Station
Sundt Unit 4		Unit 4 of the H. Wilson Sundt Generating Station
TCA		Transmission Cost Adjustor
Tenth Circuit		The United States Court of Appeals for the Tenth Circuit
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 (formerly 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 September 30, 2013, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statement of changes in stockholders’ equity for the nine-month period ended September 30, 2013 and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.

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

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

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

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

November 6, 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 September 30, 2013, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statement of changes in stockholder’s equity for the nine-month period ended September 30, 2013 and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 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

November 6, 2013

Table of Contents

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



Three Months Ended							Nine Months Ended
September 30,							September 30,
2013			2012				2013			2012
(Unaudited)							(Unaudited)
Thousands of Dollars							Thousands of Dollars
(Except Per Share Amounts)							(Except Per Share Amounts)
						Operating Revenues
$	362,244		$	353,473		Electric Retail Sales	$	868,523		$	850,975
27,529			29,341			Electric Wholesale Sales	92,581			88,469
15,430			15,407			Gas Retail Sales	86,432			85,621
31,838			35,887			Other Revenues	86,863			88,427
437,041			434,108			Total Operating Revenues	1,134,399			1,113,492
						Operating Expenses
85,102			92,873			Fuel	253,249			245,933
67,429			57,085			Purchased Energy	189,384			165,078
8,061			4,500			Transmission and Other PPFAC Recoverable Costs	15,768			10,738
(3,521		)	18,076			Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(6,814		)	29,730
157,071			172,534			Total Fuel and Purchased Energy	451,587			451,479
93,202			98,346			Operations and Maintenance	278,245			283,587
38,204			35,145			Depreciation	111,175			105,319
5,193			9,069			Amortization	21,600			26,845
13,606			12,605			Taxes Other Than Income Taxes	41,329			37,385
307,276			327,699			Total Operating Expenses	903,936			904,615
129,765			106,409			Operating Income	230,463			208,877
						Other Income (Deductions)
2			340			Interest Income	31			981
2,044			1,011			Other Income	5,545			3,855
(438		)	(752		)	Other Expense	(1,817		)	(1,508		)
731			581			Appreciation (Depreciation) in Fair Value of Investments	1,864			1,621
2,339			1,180			Total Other Income (Deductions)	5,623			4,949
						Interest Expense
17,580			17,074			Long-Term Debt	53,534			53,811
6,323			8,507			Capital Leases	18,821			25,105
230			692			Other Interest Expense	183			1,712
(933		)	(459		)	Interest Capitalized	(2,352		)	(1,646		)
23,200			25,814			Total Interest Expense	70,186			78,982
108,904			81,775			Income Before Income Taxes	165,900			134,844
40,914			31,111			Income Tax Expense	51,947			51,430
$	67,990		$	50,664		Net Income	$	113,953		$	83,414
						Weighted-Average Shares of Common Stock Outstanding (000)
41,650			41,446			Basic	41,596			39,983
42,028			41,863			Diluted	41,941			41,719
						Earnings Per Share
$	1.63		$	1.22		Basic	$	2.74		$	2.09
$	1.62		$	1.21		Diluted	$	2.72		$	2.03
$	0.435		$	0.43		Dividends Declared Per Share	$	1.305		$	1.29

See Notes to Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



Three Months Ended					Nine Months Ended
September 30,					September 30,
2013		2012			2013		2012
(Unaudited)					(Unaudited)
Thousands of Dollars					Thousands of Dollars
				Comprehensive Income
$	67,990	$	50,664	Net Income	$	113,953	$	83,414

				Other Comprehensive Income
				Net Changes in Fair Value of Cash Flow Hedges:
685		370		net of income tax expense of $(448) and $(244)
				net of income tax expense of $(1,459) and $(421)	2,229		641

				Supplemental Executive Retirement Plan (SERP) Benefit Amortization:
68		55		net of income tax expense of $(42) and $(34)
				net of income tax expense of $(127) and $(50)	205		219

753		425		Total Other Comprehensive Income, Net of Income Tax Expense	2,434		860
$	68,743	$	51,089	Total Comprehensive Income	$	116,387	$	84,274

See Notes to Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	912,098		$	894,195
Cash Receipts from Electric Wholesale Sales	118,341			107,854
Cash Receipts from Gas Retail Sales	109,994			114,055
Cash Receipts from Operating Springerville Units 3 & 4	75,552			75,715
Cash Receipts from Gas Wholesale Sales	3,558			565
Interest Received	516			2,884
Income Tax Refunds Received	—			307
Other Cash Receipts	23,514			18,810
Fuel Costs Paid	(218,712		)	(239,397		)
Purchased Energy Costs Paid	(217,522		)	(189,927		)
Payment of Operations and Maintenance Costs	(199,939		)	(207,780		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(124,782		)	(128,513		)
Wages Paid, Net of Amounts Capitalized	(96,899		)	(94,815		)
Interest Paid, Net of Amounts Capitalized	(50,108		)	(52,593		)
Capital Lease Interest Paid	(21,698		)	(27,895		)
Income Taxes Paid	(316		)	—
Other Cash Payments	(8,563		)	(5,327		)
Net Cash Flows—Operating Activities	305,034			268,138
Cash Flows from Investing Activities
Capital Expenditures	(238,463		)	(232,036		)
Purchase of Intangibles—Renewable Energy Credits	(20,429		)	(7,554		)
Deposit—San Juan Mine Reclamation Trust	—			(1,107		)
Other Cash Payments	—			(232		)
Return of Investments in Springerville Lease Debt	9,104			19,278
Restricted Cash Released	4,500			—
Proceeds from Note Receivable	—			12,500
Insurance Proceeds for Replacement Assets	—			2,875
Other Cash Receipts	6,625			14,484
Net Cash Flows—Investing Activities	(238,663		)	(191,792		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	130,000			342,000
Repayments of Borrowings Under Revolving Credit Facilities	(100,000		)	(346,000		)
Payments of Capital Lease Obligations	(99,621		)	(89,452		)
Common Stock Dividends Paid	(54,146		)	(51,852		)
Proceeds from Issuance of Long-Term Debt	—			149,513
Repayments of Long-Term Debt	—			(9,341		)
Payment of Debt Issue/Retirement Costs	(1,022		)	(3,349		)
Proceeds from Stock Options Exercised	2,724			3,529
Proceeds from Common Stock Issuance	408			—
Other Cash Receipts	4,721			2,935
Other Cash Payments	(962		)	(718		)
Net Cash Flows—Financing Activities	(117,898		)	(2,735		)
Net Increase (Decrease) in Cash and Cash Equivalents	(51,527		)	73,611
Cash and Cash Equivalents, Beginning of Year	123,918			76,390
Cash and Cash Equivalents, End of Period	$	72,391		$	150,001

See Note 10 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,			December 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	5,114,426		$	5,005,768
Utility Plant Under Capital Leases	621,247			582,669
Construction Work in Progress	211,100			128,621
Total Utility Plant	5,946,773			5,717,058
Less Accumulated Depreciation and Amortization	(1,966,801		)	(1,921,733		)
Less Accumulated Amortization of Capital Lease Assets	(509,712		)	(494,962		)
Total Utility Plant—Net	3,470,260			3,300,363
Investments and Other Property
Investments in Lease Equity	36,230			36,339
Other	33,441			36,537
Total Investments and Other Property	69,671			72,876
Current Assets
Cash and Cash Equivalents	72,391			123,918
Accounts Receivable—Customer	127,316			93,742
Unbilled Accounts Receivable	55,730			53,568
Allowance for Doubtful Accounts	(7,215		)	(6,545		)
Materials and Supplies	89,302			93,322
Fuel Inventory	44,458			62,019
Deferred Income Taxes—Current	66,520			34,260
Regulatory Assets—Current	52,709			51,619
Investments in Lease Debt	—			9,118
Derivative Instruments	1,620			3,165
Other	26,882			33,567
Total Current Assets	529,713			551,753
Regulatory and Other Assets
Regulatory Assets—Noncurrent	200,705			191,077
Derivative Instruments	752			3,801
Other Assets	22,704			20,559
Total Regulatory and Other Assets	224,161			215,437
Total Assets	$	4,293,805		$	4,140,429

See Notes to Condensed Consolidated Financial Statements.

(Continued)

UNS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,		December 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,132,286	$	1,065,465
Capital Lease Obligations	130,088		262,138
Long-Term Debt	1,505,536		1,498,442
Total Capitalization	2,767,910		2,826,045
Current Liabilities
Current Obligations Under Capital Leases	169,060		90,583
Borrowings Under Revolving Credit Facilities	23,000		—
Accounts Payable—Trade	91,615		107,740
Accrued Taxes Other than Income Taxes	60,657		41,939
Accrued Employee Expenses	26,000		24,094
Accrued Interest	22,343		31,950
Regulatory Liabilities—Current	56,987		43,516
Customer Deposits	30,564		34,048
Derivative Instruments	12,988		14,742
Other	14,521		10,517
Total Current Liabilities	507,735		399,129
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	482,516		364,756
Regulatory Liabilities—Noncurrent	297,699		279,111
Pension and Other Retiree Benefits	141,997		159,401
Derivative Instruments	7,183		12,709
Other	88,765		99,278
Total Deferred Credits and Other Liabilities	1,018,160		915,255
Commitments, Contingencies, and Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	4,293,805	$	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				113,953						113,953
Other Comprehensive Income, net of $(1,586) income taxes							2,434			2,434
Total Comprehensive Income										116,387
Dividends, Including Non-Cash Dividend Equivalents				(54,733		)				(54,733		)
Shares Issued Under Dividend Reinvestment Plan	9	408								408
Shares Issued for Stock Options	85	2,724								2,724
Shares Issued Under Performance Share Awards	57	—								—
Other		2,035								2,035
Balances at September 30, 2013	41,495	$	887,305	$	252,337		$	(7,356	)	$	1,132,286

* 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



Three Months Ended							Nine Months Ended
September 30,							September 30,
2013			2012				2013			2012
(Unaudited)							(Unaudited)
Thousands of Dollars							Thousands of Dollars
						Operating Revenues
$	310,632		$	302,893		Electric Retail Sales	$	739,147		$	716,993
26,563			25,448			Electric Wholesale Sales	90,503			77,488
34,044			38,569			Other Revenues	93,603			95,826
371,239			366,910			Total Operating Revenues	923,253			890,307
						Operating Expenses
82,065			88,402			Fuel	247,417			237,930
42,477			27,576			Purchased Power	89,815			62,064
4,940			1,914			Transmission and Other PPFAC Recoverable Costs	7,535			4,277
(7,992		)	20,025			Increase (Decrease) to Reflect PPFAC Recovery Treatment	(5,079		)	25,150
121,490			137,917			Total Fuel and Purchased Energy	339,688			329,421
79,335			86,942			Operations and Maintenance	239,170			248,092
30,311			27,644			Depreciation	87,729			82,656
6,118			10,001			Amortization	24,393			29,621
10,808			10,327			Taxes Other Than Income Taxes	32,916			30,325
248,062			272,831			Total Operating Expenses	723,896			720,115
123,177			94,079			Operating Income	199,357			170,192
						Other Income (Deductions)
6			28			Interest Income	14			97
1,466			952			Other Income	3,904			3,041
(2,776		)	(1,945		)	Other Expense	(7,493		)	(4,886		)
731			581			Appreciation (Depreciation) in Fair Value of Investments	1,864			1,621
(573		)	(384		)	Total Other Income (Deductions)	(1,711		)	(127		)
						Interest Expense
13,848			13,268			Long-Term Debt	42,412			40,562
6,323			8,507			Capital Leases	18,821			25,105
82			562			Other Interest Expense	(86		)	1,338
(644		)	(361		)	Interest Capitalized	(1,671		)	(1,381		)
19,609			21,976			Total Interest Expense	59,476			65,624
102,995			71,719			Income Before Income Taxes	138,170			104,441
38,828			27,150			Income Tax Expense	41,737			39,423
$	64,167		$	44,569		Net Income	$	96,433		$	65,018

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



Three Months Ended					Nine Months Ended
September 30,					September 30,
2013		2012			2013		2012
(Unaudited)					(Unaudited)
Thousands of Dollars					Thousands of Dollars
				Comprehensive Income
$	64,167	$	44,569	Net Income	$	96,433	$	65,018

				Other Comprehensive Income
				Net Changes in Fair Value of Cash Flow Hedges:
700		465		net of income tax expense of $(458) and $(304)
				net of income tax expense of $(1,412) and $(584)	2,156		891

				SERP Benefit Amortization:
68		55		net of income tax expense of $(42) and $(34)
				net of income tax expense of $(127) and $(50)	205		219

768		520		Total Other Comprehensive Income, Net of Income Tax Expense	2,361		1,110
$	64,935	$	45,089	Total Comprehensive Income	$	98,794	$	66,128

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2013			2012
	(Unaudited)
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	769,433		$	748,936
Cash Receipts from Electric Wholesale Sales	107,997			89,902
Cash Receipts from Operating Springerville Units 3 & 4	75,552			75,715
Reimbursement of Affiliate Charges	17,639			16,783
Cash Receipts from Gas Wholesale Sales	3,209			153
Interest Received	509			2,014
Income Tax Refunds Received	77			200
Other Cash Receipts	18,240			14,528
Fuel Costs Paid	(214,722		)	(233,457		)
Payment of Operations and Maintenance Costs	(193,290		)	(200,569		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(97,419		)	(99,249		)
Purchased Power Costs Paid	(87,110		)	(60,684		)
Wages Paid, Net of Amounts Capitalized	(80,964		)	(77,820		)
Interest Paid, Net of Amounts Capitalized	(36,671		)	(35,728		)
Capital Lease Interest Paid	(21,698		)	(27,893		)
Income Taxes Paid	—			(1,796		)
Other Cash Payments	(6,603		)	(3,884		)
Net Cash Flows—Operating Activities	254,179			207,151
Cash Flows from Investing Activities
Capital Expenditures	(180,451		)	(196,429		)
Purchase of Intangibles—Renewable Energy Credits	(17,552		)	(6,436		)
Deposit—San Juan Mine Reclamation Trust	—			(1,107		)
Return of Investments in Springerville Lease Debt	9,104			19,278
Restricted Cash Released	4,500			—
Insurance Proceeds for Replacement Assets	—			2,875
Other Cash Receipts	4,656			9,207
Net Cash Flows—Investing Activities	(179,743		)	(172,612		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	78,000			189,000
Repayments of Borrowings Under Revolving Credit Facility	(78,000		)	(199,000		)
Payments of Capital Lease Obligations	(99,621		)	(89,452		)
Dividends Paid to UNS Energy	(20,000		)	—
Proceeds from Issuance of Long-Term Debt	—			149,513
Repayments of Long-Term Debt	—			(6,535		)
Payment of Debt Issue/Retirement Costs	(1,022		)	(3,349		)
Other Cash Receipts	1,976			1,292
Other Cash Payments	(726		)	(530		)
Net Cash Flows—Financing Activities	(119,393		)	40,939
Net Increase (Decrease) in Cash and Cash Equivalents	(44,957		)	75,478
Cash and Cash Equivalents, Beginning of Year	79,743			27,718
Cash and Cash Equivalents, End of Period	$	34,786		$	103,196

See Note 10 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,			December 31,
	2013			2012
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	4,434,770		$	4,348,041
Utility Plant Under Capital Leases	621,247			582,669
Construction Work in Progress	153,258			98,460
Total Utility Plant	5,209,275			5,029,170
Less Accumulated Depreciation and Amortization	(1,811,806		)	(1,783,787		)
Less Accumulated Amortization of Capital Lease Assets	(509,712		)	(494,962		)
Total Utility Plant—Net	2,887,757			2,750,421
Investments and Other Property
Investments in Lease Equity	36,230			36,339
Other	32,009			35,091
Total Investments and Other Property	68,239			71,430
Current Assets
Cash and Cash Equivalents	34,786			79,743
Accounts Receivable—Customer	105,646			71,813
Unbilled Accounts Receivable	46,240			33,782
Allowance for Doubtful Accounts	(5,238		)	(4,598		)
Accounts Receivable—Due from Affiliates	3,963			5,720
Materials and Supplies	76,255			80,377
Fuel Inventory	44,162			61,737
Deferred Income Taxes—Current	69,985			37,212
Regulatory Assets—Current	36,283			34,345
Investments in Lease Debt	—			9,118
Derivative Instruments	1,047			2,230
Other	20,605			32,163
Total Current Assets	433,734			443,642
Regulatory and Other Assets
Regulatory Assets—Noncurrent	186,626			178,330
Derivative Instruments	259			1,354
Other Assets	17,525			15,869
Total Regulatory and Other Assets	204,410			195,553
Total Assets	$	3,594,140		$	3,461,046

See Notes to Condensed Consolidated Financial Statements.

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,		December 31,
	2013		2012
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	939,721	$	860,927
Capital Lease Obligations	130,088		262,138
Long-Term Debt	1,223,536		1,223,442
Total Capitalization	2,293,345		2,346,507
Current Liabilities
Current Obligations Under Capital Leases	169,060		90,583
Accounts Payable—Trade	75,834		82,122
Accounts Payable—Due to Affiliates	2,981		3,134
Accrued Taxes Other than Income Taxes	50,465		33,060
Accrued Employee Expenses	22,937		20,715
Accrued Interest	20,503		26,965
Regulatory Liabilities—Current	26,440		20,822
Customer Deposits	21,251		24,846
Derivative Instruments	7,060		4,899
Other	9,336		7,085
Total Current Liabilities	405,867		314,231
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	421,621		319,216
Regulatory Liabilities—Noncurrent	259,523		241,189
Pension and Other Retiree Benefits	132,491		149,718
Derivative Instruments	4,950		10,565
Other	76,343		79,620
Total Deferred Credits and Other Liabilities	894,928		800,308
Commitments, Contingencies, and Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	3,594,140	$	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 Earnings (Deficit)			Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	(Unaudited) Thousands of Dollars
Balances at December 31, 2012	$	888,971	$	(6,357	)	$	(12,157	)	$	(9,530	)	$	860,927
Comprehensive Income
2013 Year-to-Date Net Income						96,433						96,433
Other Comprehensive Income, net of $(1,539) income taxes									2,361			2,361
Total Comprehensive Income												98,794
Dividends Paid						(20,000		)				(20,000		)
Balances at September 30, 2013	$	888,971	$	(6,357	)	$	64,276		$	(7,169	)	$	939,721

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 our 2012 Annual Report on Form 10-K.

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

REVISION OF PRIOR PERIOD UNS ENERGY INCOME STATEMENT

During the first three quarters of 2012, we incorrectly reported UNS Electric's sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $3 million for the three months ended and $10 million for the nine months ended September 30, 2012. This error had no impact on operating income, net income, accumulated 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				Nine Months Ended
	September 30, 2012				September 30, 2012
	As Reported		As Revised		As Reported		As Revised
	Thousands of Dollars				Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	32,494	$	29,341	$	98,282	$	88,469
Purchased Energy	60,238		57,085		174,891		165,078
Total Fuel and Purchased Energy	175,687		172,534		461,292		451,479
Total Operating Expenses	330,852		327,699		914,428		904,615

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2013, we adopted authoritative guidance that:


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


•	Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 12.

•

Allows an entity to perform a qualitative analysis to determine if additional testing for impairment of indefinite-lived intangible assets is required. Based on our qualitative analysis, we had no impairment indicator as our only indefinite-lived intangible assets, Renewable Energy Credits (RECs), are currently recoverable under the Renewable Energy Standard (RES) as we use the RECs to comply with the standard’s renewable resources requirements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 2. REGULATORY MATTERS

RATES AND REGULATION

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

2013 TEP RATE ORDER

In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012 which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

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


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


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


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


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


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


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


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

The 2013 TEP Rate Order also includes the following cost recovery mechanisms:


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


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


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


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


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

•

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited


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

PENDING 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. UNS Electric's rate filing was based on a test year ended June 30, 2012.

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

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


•	an increase in non-fuel retail Base Rates of approximately $3 million;


•	an OCRB of approximately $213 million and a FVRB of approximately $283 million;


•	a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;


•	a 0.50% 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 $70 million); and


•	a capital structure of 52.6% equity and 47.4% long-term debt.

The 2013 UNS Electric Settlement Agreement also includes the following cost recovery mechanisms:


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


•	a Transmission Cost Adjustor (TCA). The TCA would allow more timely recovery of transmission costs associated with serving retail customers.

UNS GAS PURCHASED GAS ADJUSTOR

In October 2013, the ACC approved an increase to the existing Purchased Gas Adjustor (PGA) credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At September 30, 2013, the PGA bank balance was over-collected by $17 million on a billed-to-customer basis.

REGULATORY ASSETS AND LIABILITIES

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



	September 30, 2013						December 31, 2012
	UNS Energy			TEP			UNS Energy			TEP
	Millions of Dollars
Regulatory Assets – Current	$	53		$	36		$	52		$	34
Regulatory Assets – Noncurrent ⁽¹⁾	201			187			191			178
Regulatory Liabilities – Current ⁽²⁾	(57		)	(26		)	(44		)	(21		)
Regulatory Liabilities – Noncurrent ⁽³⁾	(298		)	(260		)	(279		)	(241		)
Total Net Regulatory Assets (Liabilities)	$	(101	)	$	(63	)	$	(80	)	$	(50	)


⁽¹⁾	Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment. See Note 6. This regulatory asset does not earn a return and will be recovered through future

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.


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


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

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF REGULATORY ACCOUNTING

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


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


•	reflecting regulatory pension assets as part of AOCI.

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


•	TEP would have recorded an extraordinary after-tax gain of $113 million and an after-tax loss in AOCI of $75 million;


•	UNS Gas would have recorded an extraordinary after-tax gain of $26 million and an after-tax loss in AOCI of $2 million; and


•	UNS Electric would have recorded an extraordinary after-tax gain of $3 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 and our largest subsidiary


(2)	UNS Gas, a regulated gas distribution utility


(3)	UNS Electric, a regulated electric utility

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



	Reportable Segments
	TEP		UNS Gas			UNS Electric		Non-Reportable Segments		Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Three Months Ended September 30, 2013
Operating Revenues – External	$	367	$	16		$	54	$	—	$	—		$	437
Operating Revenues – Intersegment⁽¹⁾	4		2			—		4		(10		)	—
Net Income	64		(1		)	5		—		—			68

Three Months Ended September 30, 2012
Operating Revenues – External	$	362	$	16		$	56	$	—	$	—		$	434
Operating Revenues – Intersegment⁽¹⁾	5		2			—		5		(12		)	—
Net Income	45		—			6		—		—			51

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	Reportable Segments
	TEP		UNS Gas		UNS Electric		Non-Reportable Segments			Reconciling Adjustments			UNS Energy Consolidated
	Millions of Dollars
Income Statement
Nine Months Ended September 30, 2013
Operating Revenues – External	$	910	$	90	$	134	$	—		$	—		$	1,134
Operating Revenues – Intersegment⁽¹⁾	13		3		1		12			(29		)	—
Net Income	96		6		11		1			—			114

Nine Months Ended September 30, 2012
Operating Revenues – External	$	877	$	89	$	147	$	—		$	—		$	1,113
Operating Revenues – Intersegment⁽¹⁾	13		4		1		14			(32		)	—
Net Income	65		5		14		(1		)	—			83

⁽¹⁾

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

NOTE 4. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

In addition those reported in our 2012 Annual Report on Form 10-K, we entered into the following new long-term commitments through September 30, 2013:

TEP COMMITMENTS



	Purchase Commitments
	2013		2014		2015		2016		2017		Thereafter		Total
	Millions of Dollars
Purchased Power, Including Renewable PPA⁽¹⁾	$	2	$	18	$	6	$	4	$	4	$	58	$	92
Capital Lease Obligations⁽²⁾	—		—		46		—		—		—		46
RES Performance-Based Incentives⁽³⁾	1		1		1		1		1		7		12
Fuel Transportation⁽⁴⁾	4		5		5		5		5		1		25
Total Purchase Commitments	$	7	$	24	$	58	$	10	$	10	$	66	$	175


⁽¹⁾	Purchased Power costs are recoverable from customers through the PPFAC. A portion of the Renewable Power Purchase Agreement (PPA) is recoverable through the PPFAC, with the balance recoverable through the RES tariff.


⁽²⁾	In the third and fourth quarters of 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 5.


⁽³⁾	The RES Performance-Based Incentive (PBI) costs are recoverable through the RES tariff.


(4)	Fuel Transportation costs are recoverable from customers through the PPFAC.

UNS GAS COMMITMENTS

Forward Energy Contracts

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

Fuel Transportation

UNS Gas entered into revised gas transportation agreements in August 2013. UNS Gas anticipates that its commitments will increase by $3 million in 2013, $9 million each year in 2014 through 2016, $10 million in 2017, and $56 million thereafter.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

UNS ELECTRIC COMMITMENTS

Purchased Power Contracts

UNS Electric entered into new forward purchased power commitments that will settle through 2015 at fixed prices per MWh. UNS Electric’s minimum payment obligations for these purchases are $1 million in 2014 and $4 million in 2015.

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.

In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. All parties filed a joint motion to stay until December 1, 2013.

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.

In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. The coal supplier and Four Corners’ operating agent intend to contest the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. TEP cannot predict the outcome or timing of resolution of this claim.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) recorded was $18 million at September 30, 2013 and $16 million at December 31, 2012.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

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

Tucson to Nogales Transmission Line

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

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

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 require mercury emission control equipment by 2015. TEP's share of the estimated capital cost of this equipment is less than $1 million. TEP expects its share of the annual operating cost of the mercury emission control equipment to be less than $1 million.

Springerville Generating Station

Based on the EPA’s final standards, Springerville Generating Station (Springerville) may require 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

Sundt Generating Station

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

Regional Haze Rules

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

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

Navajo

In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, submitted an agreement to the EPA that would achieve greater NOx emission reductions than the EPA's proposed BART rule. In September 2013, EPA issued a supplemental proposal incorporating the provisions of the agreement as a better-than-BART alternative.

Among other things, the agreement calls for the shut down of one unit or an equivalent reduction in emissions by 2020. The shutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install SCR or an equivalent technology on the remaining two units by 2030. As part of the agreement, the current owners have committed to cease their operation of conventional coal-fired generation at Navajo no later than December 2044. The Navajo Nation can continue operation after 2044 at its election. If SCR technology is ultimately implemented 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 United States Court of Appeals for the Tenth Circuit (Tenth Circuit). In addition, the operator filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA's reconsideration and review by the Tenth Circuit. The State of New Mexico filed similar motions with the Tenth Circuit and the EPA. Several environmental groups were granted permission to join in opposition to PNM's petition to review in the Tenth Circuit. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP's five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Tenth Circuit denied PNM's and the State of New Mexico's motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the court's decision. In February 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals.

In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement that outlines an alternative to the FIP. The terms of the agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of Selective Non-Catalytic Reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. The New Mexico Environmental Department (NMED) prepared a revision to the regional haze SIP incorporating the provisions of the agreement, and in September 2013, the New Mexico Environmental Improvement Board approved the SIP revision. The SIP revision now awaits final EPA approval.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $35 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At September 30, 2013, the book value of TEP's share of San Juan Unit 2 was $114 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. APS must select which FIP alternative to implement by December 31, 2013. In either case, TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $35 million. TEP's share of incremental annual operating costs for SCR is estimated at $2 million.

Springerville

The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville. Other provisions of the Regional Haze Rule requiring further emission reduction are not likely to impact Springerville operations until after 2018.

Sundt

In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule. Under the Regional Haze Rule, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART determination. The EPA postponed its expected release of a proposed BART requirement for Sundt Unit 4 until December 2013, with a final determination expected in May 2014. While TEP does not agree that Sundt Unit 4 is BART eligible, in anticipation of EPA's proposed BART requirements, TEP has submitted a plan for EPA approval proposing to eliminate coal as a fuel after December 2017.

Greenhouse Gas Regulation

In June 2013, President Obama directed the EPA to move forward with carbon emission regulations for both new and existing fossil-fueled power plants.

In September 2013, the EPA issued a re-proposed rule for new power plants. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

For existing power plants, the President ordered the EPA to:


•	propose carbon emission standards by June 1, 2014;


•	finalize those standards by June 1, 2015; and


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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 5. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

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

TEP SPRINGERVILLE UNIT 1 CAPITAL LEASE PURCHASE COMMITMENTS

In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a continuous capacity rating of 387 MW. The appraisal price was challenged, and TEP initiated a proceeding in 2012 seeking judicial confirmation of the results of the appraisal process.

In October 2013, TEP elected to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of continuous operating capability, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014.

Upon close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of continuous operating capability. Due to TEP's purchase commitment, TEP and UNS Energy expect to record an increase of approximately $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets, of which $39 million is reflected as of September 30, 2013.

Because the owner participants whose leased interests TEP elected to purchase have agreed to sell their interests for amounts equal to the appraised value, TEP dismissed the legal action associated with the appraisal.

TEP TAX-EXEMPT BONDS ISSUED

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

UNS ENERGY'S AND TEP'S CREDIT RATING UPGRADES

In June 2013, the pricing under certain debt agreements improved as a result of an upgrade in the credit ratings of UNS Energy and TEP.


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


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


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

TEP MORTGAGE INDENTURE

Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP (i) requested $423 million in mortgage bonds be returned to TEP for cancellation, and (ii) discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured, which changed the pricing of the following agreements, with pricing tied to credit ratings for short-term borrowings:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited


•	Under the TEP Credit Agreement, the interest rate increased from LIBOR plus 1.0% to LIBOR plus 1.25%; and the margin rate on the $186 million letter of credit facility increased from 1.0% to 1.25%; and


•	Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit increased from 1.25% to 1.75% per annum.

COVENANT COMPLIANCE

At September 30, 2013, we were in compliance with the terms of our credit agreements, the 2010 TEP Reimbursement Agreement, and UNS Electric's term loan.

NOTE 6. INCOME TAXES

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



	UNS Energy						TEP
	Three Months Ended September 30,
	2013			2012			2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	38		$	29		$	36		$	25
State Income Tax Expense, Net of Federal Deduction	5			3			5			3
Federal/State Tax Credits	(1		)	(1		)	(1		)	(1		)
Other	(1		)	—			(1		)	—
Total Federal and State Income Tax Expense	41			$	31		$	39		$	27



	UNS Energy						TEP
	Nine Months Ended September 30,
	2013			2012			2013			2012
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	58		$	47		$	48		$	37
State Income Tax Expense, Net of Federal Deduction	8			6			6			4
Federal/State Tax Credits	(2		)	(1		)	(2		)	(1		)
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—			(11		)	—
Other	(1		)	(1		)	1			(1		)
Total Federal and State Income Tax Expense	$	52		$	51		$	42		$	39

Investment Tax Credit Basis Difference Adjustment

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

Uncertain Tax Positions

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	UNS Energy			TEP
	Millions of Dollars
Unrecognized Tax Benefits at December 31, 2012	$	30		$	23
Additions Based on Tax Positions Taken in the Current Year	1			1
Reduction of Positions from Prior Year Based on Tax Authority Ruling	(27		)	(22		)
Unrecognized Tax Benefits at September 30, 2013	$	4		$	2

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

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

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

Tangible Repairs Regulation

In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. Management believes that adoption of these regulations will not result in a material change to plant-related deferred tax liabilities.

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 September 30,
	2013			2012			2013		2012
	Millions of Dollars

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



	Pension Benefits						Other Retiree Benefits
	Nine Months Ended September 30,
	2013			2012			2013			2012
	Millions of Dollars

Service Cost	$	10		$	8		$	3		$	2
Interest Cost	11			12			2			2
Expected Return on Plan Assets	(15		)	(13		)	(1		)	—
Actuarial Loss Amortization	7			5			—			—
Net Periodic Benefit Cost	$	13		$	12		$	4		$	4

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 8. SHARE-BASED COMPENSATION PLANS

RESTRICTED STOCK UNITS

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

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

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 companies included in the Edison Electric Institute Index during the performance period of January 1, 2013 through December 31, 2015. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date share price, of $46.23 per share and will be paid out in Common Stock based on cumulative net income for the three-year period ended December 31, 2015. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.

SHARE-BASED COMPENSATION EXPENSE

UNS Energy and TEP recorded $1 million of share-based compensation expense for the three months ended September 30, 2013 and September 30, 2012. For the nine months ended September 30, 2013, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. For the nine months ended September 30, 2012, UNS Energy and TEP recorded share-based compensation expense of $2 million.

At September 30, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $4 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At September 30, 2013, 1 million shares were awarded but not yet issued, including performance shares, under the share-based compensation plans.

NOTE 9. UNS ENERGY EARNINGS PER SHARE

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	Thousands of Dollars
Numerator:
Net Income	$	67,990	$	50,664	$	113,953	$	83,414
Income from Assumed Conversion of Convertible Senior Notes ⁽¹⁾	—		—		—		1,100
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	67,990	$	50,664	$	113,953	$	84,514

	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,472		41,290		41,427		39,835
Fully Vested Deferred Stock Units	178		156		169		148
Total Weighted Average Common Stock Outstanding – Basic	41,650		41,446		41,596		39,983
Effect of Dilutive Securities:
Convertible Senior Notes ⁽¹⁾	—		—		—		1,417
Options and Stock Issuable Under Share-Based Compensation Plans	378		417		345		319
Total Weighted Average Common Stock Outstanding – Diluted	42,028		41,863		41,941		41,719

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

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
	Thousands of Shares
Stock Options	—	—	—	67
Restricted Stock Units	—	—	8	—
Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	—	—	8	67

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

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



	UNS Energy
	Nine Months Ended September 30,
	2013			2012
	Thousands of Dollars
Net Income	$	113,953		$	83,414
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	111,175			105,319
Amortization Expense	21,600			26,845
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	5,399			4,911
Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,280			2,250
Provision for Retail Customer Bad Debts	1,703			2,017
Use of RECs for Compliance	12,999			4,017
Deferred Income Taxes	77,962			63,057
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—
Pension and Retiree Expense	17,087			16,391
Pension and Retiree Funding	(27,602		)	(23,649		)
Share-Based Compensation Expense	2,810			1,952
Allowance for Equity Funds Used During Construction	(4,145		)	(2,708		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(6,814		)	29,730
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Liquidated Damages for Springerville Unit 3 Outage	—			1,921
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(32,883		)	(28,686		)
Materials and Fuel Inventory	14,839			(33,038		)
Accounts Payable	(18,497		)	(5,220		)
Income Taxes	(15,847		)	(11,738		)
Interest Accrued	(2,137		)	(1,551		)
Taxes Other Than Income Taxes	18,718			16,478
Other	20,473			16,426
Net Cash Flows – Operating Activities	$	305,034		$	268,138

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	TEP
	Nine Months Ended September 30,
	2013			2012
	Thousands of Dollars
Net Income	$	96,433		$	65,018
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	87,729			82,656
Amortization Expense	24,393			29,621
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense	4,602			3,922
Amortization of Deferred Debt-Related Costs Included in Interest Expense	1,831			1,628
Provision for Retail Customer Bad Debts	1,315			1,348
Use of RECs for Compliance	11,766			3,324
Deferred Income Taxes	64,132			51,638
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—
Pension and Retiree Expense	14,909			14,466
Pension and Retiree Funding	(26,118		)	(20,989		)
Share-Based Compensation Expense	2,239			1,540
Allowance for Equity Funds Used During Construction	(2,923		)	(2,265		)
Increase (Decrease) to Reflect PPFAC Recovery	(5,079		)	25,150
PPFAC Reduction - 2013 TEP Rate Order	3,000			—
Liquidated Damages for Springerville Unit 3 Outage	—			1,921
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(42,542		)	(44,269		)
Materials and Fuel Inventory	14,955			(32,448		)
Accounts Payable	(8,678		)	4,977
Income Taxes	(10,681		)	(11,424		)
Interest Accrued	1,008			2,729
Taxes Other Than Income Taxes	17,405			16,710
Other	15,234			11,898
Net Cash Flows – Operating Activities	$	254,179		$	207,151

Non-Cash Transactions

In August 2013, TEP recorded an increase of $39 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in January 2015. See Note 5.

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

In September 2012, TEP declared a $30 million dividend to UNS Energy which was paid in October 2012.

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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 11. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

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

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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


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


•	For Investment in Lease Debt, we calculated 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 incorporated the impact of counterparty credit risk using market credit default swap data. TEP's Investment in Lease Debt matured in January 2013.


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

•

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

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



		September 30, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		24		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,506		1,522		1,498		1,583
TEP	Level 2	1,224		1,215		1,223		1,271

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets⁽⁵⁾			Net Amount
	September 30, 2013
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	31		$	31	$	—		$	—		$	—		$	31
Restricted Cash⁽¹⁾	2			2		—			—			—			2
Rabbi Trust Investments⁽²⁾	21			—		21			—			—			21
Energy Contracts - Regulatory Recovery⁽³⁾	2			—		1			1			(2		)	—
Total Assets	56			33		22			1			(2		)	54
Liabilities
Energy Contracts - Regulatory Recovery⁽³⁾	(11		)	—		(5		)	(6		)	2			(9		)
Energy Contracts - Cash Flow Hedge⁽³⁾	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps⁽⁴⁾	(8		)	—		(8		)	—			—			(8		)
Total Liabilities	(20		)	—		(13		)	(7		)	2			(18		)
Net Total Assets (Liabilities)	$	36		$	33	$	9		$	(6	)	$	—		$	36



	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets⁽⁵⁾			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash⁽¹⁾	7			7		—			—			—			7
Rabbi Trust Investments⁽²⁾	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery⁽³⁾	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery⁽³⁾	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge⁽³⁾	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps⁽⁴⁾	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets⁽⁵⁾			Net Amount
	September 30, 2013
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	15		$	15	$	—		$	—		$	—		$	15
Restricted Cash⁽¹⁾	2			2		—			—			—			2
Rabbi Trust Investments⁽²⁾	21			—		21			—			—			21
Energy Contracts - Regulatory Recovery⁽³⁾	1			—		1			—			(1		)	—
Total Assets	39			17		22			—			(1		)	38
Liabilities
Energy Contracts - Regulatory Recovery⁽³⁾	(3		)	—		(2		)	(1		)	1			(2		)
Energy Contracts - Cash Flow Hedge⁽³⁾	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps⁽⁴⁾	(8		)	—		(8		)	—			—			(8		)
Total Liabilities	(12		)	—		(10		)	(2		)	1			(11		)
Net Total Assets (Liabilities)	$	27		$	17	$	12		$	(2	)	$	—		$	27



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


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


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

⁽³⁾

Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas 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 on the UNS Energy and TEP balance sheets. The valuation techniques are described below.


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


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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

DERIVATIVE INSTRUMENTS

Regulatory Recovery

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

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.

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

We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. Beginning in the third quarter of 2013, the fair value of our power options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented.

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

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

Cash Flow Hedges

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

Financial Impact of Energy Contracts

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



	UNS Energy					TEP
	Three Months Ended September 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	1	$	(12	)	$	1	$	(6	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	UNS Energy					TEP
	Nine Months Ended September 30,
	2013		2012			2013		2012
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	—	$	(20	)	$	2	$	(7	)

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

Derivative Volumes

The volumes associated with our energy contracts were as follows:



	UNS Energy		TEP
	September 30, 2013	December 31, 2012	September 30, 2013	December 31, 2012
Power Contracts GWh	1,819	2,228	856	820
Gas Contracts GBtu	29,022	17,851	8,504	7,958

Level 3 Fair Value Measurements

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



		Fair Value at
		September 30, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts⁽¹⁾	Market approach	$	1	$	(7	)	Market price per MWh	$	23.00	-	$	48.00


⁽¹⁾	TEP comprises $2 million of the forward contract liabilities.

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

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



	Three Months Ended September 30, 2013
	UNS Energy			TEP
	Millions of Dollars
Balances at June 30, 2013	$	(5	)	$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(3		)	(1		)
Settlements	2			—
Balances at September 30, 2013	$	(6	)	$	(2	)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited



	Nine Months Ended September 30, 2013
	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)	(2		)
Settlements	3			—
Balances at September 30, 2013	$	(6	)	$	(2	)

Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(5	)	$	(1	)



	Three Months Ended September 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at June 30, 2012	$	(7	)	$	(1	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	—			1
Settlements	1			—
Balances at September 30, 2012	$	(6	)	$	—

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



	Nine Months Ended September 30, 2012
	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(4		)	—
Settlements	8			—
Balances at September 30, 2012	$	(6	)	$	—

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

CREDIT RISK

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. The impact of counterparty credit risk and our own credit risk on the fair value of derivative contracts was less than $0.5 million at September 30, 2013 and at December 31, 2012.

Material adverse changes could trigger credit risk-related contingent features. At September 30, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $35 million for UNS Energy and $13 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $35 million for UNS Energy and $13 million for TEP.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 12. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The realized changes in AOCI 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 September 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(350	)	$	(296	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(612		)	(612		)	Interest Expense Capital Leases
Commodity Contracts	(556		)	(556		)	Purchased Energy/Purchased Power
Tax Benefit	601			579
Realized Losses on Cash Flow Hedges, Net of Taxes	(917		)	(885		)

Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(110		)	(110		)	Other Expense
Tax Benefit	42			42
Amortization, Net of Taxes	(68		)	(68		)

Total Reclassifications from Other Comprehensive Income for the Period	$	(985	)	$	(953	)



Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Nine Months Ended September 30, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(1,026	)	$	(871	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(1,820		)	(1,820		)	Interest Expense Capital Leases
Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
Tax Benefit	1,420			1,360
Realized Losses on Cash Flow Hedges, Net of Taxes	(2,173		)	(2,078		)

Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(332		)	(332		)	Other Expense
Tax Benefit	127			127
Amortization, Net of Taxes	(205		)	(205		)

Total Reclassifications from Other Comprehensive Income for the Period	$	(2,378	)	$	(2,283	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited

NOTE 13. POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY

In August 2013, TEP entered into exclusive negotiations with Entegra Power Group LLC (Entegra) to purchase Unit 3 of the Gila River Generating Station (Gila River Unit 3) located in Gila Bend, Arizona. Gila River Unit 3 is a gas-fired combined cycle unit with a nominal capacity rating of 550 MW. Although there can be no assurance that TEP and Entegra will reach agreement on TEP's purchase of Gila River Unit 3, TEP anticipates that, if such an agreement is reached, definitive purchase and sale agreements would be executed prior to year-end 2013. TEP further anticipates any such purchase would close by year-end 2014 and would be subject to, among other things, the receipt of required regulatory approvals. UNS Electric may purchase up to 150 MW of Gila River Unit 3, while TEP would purchase the remaining capacity.

NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board (FASB) issued 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. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors. This guidance will be effective in the first quarter of 2014. We do not expect the adoption of this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair value and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such change to be material. In addition, there will be no changes in the presentations of our other financial statements.

NOTE 15. REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The UNS Energy and TEP condensed consolidated financial statements as of September 30, 2013, and for the three-month and nine-month periods ended September 30, 2013 and 2012, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their reports (dated November 6, 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 third quarter and first nine months of 2013, compared with the same periods in 2012;


•	factors affecting our results and outlook;


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


•	dividends; and


•	critical accounting estimates.

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

UNS ENERGY CORPORATION

OVERVIEW OF CONSOLIDATED BUSINESS

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

TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of September 30, 2013. TEP generates, transmits, and distributes electricity to approximately 412,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. Beginning on July 1, 2013, TEP revised its methodology for counting customers as a result of rate design changes from TEP's new retail rate structure. By applying the same revised methodology to the period ended September 30, 2012, TEP's retail customer count increased by approximately 0.8%.

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 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.

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

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

OUTLOOK AND STRATEGIES

Our financial prospects and outlook are affected by many factors including: national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:

•

Developing 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.

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


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


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


•	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 net income by business segment:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
	Millions of Dollars
TEP	$	64		$	45	$	96	$	65
UNS Gas	(1		)	—		6		5
UNS Electric	5			6		11		14
Other Non-Reportable Segments and Adjustments ⁽¹⁾	—			—		1		(1		)
Consolidated Net Income	$	68		$	51	$	114	$	83


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

Executive Overview

Third Quarter of 2013 Compared with the Third Quarter of 2012

TEP

TEP reported net income of $64 million in the third quarter of 2013 compared with net income of $45 million in the third quarter of 2012. The increase in net income is due in part to: a $30 million increase in retail margin revenues related to a non-fuel base rate increase that was effective on July 1, 2013 and higher retail kWh sales resulting from an increase in Cooling Degree Days; a $1 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; and a $2 million decrease in interest expense due in part to a redcution in capital lease obligation balances; partially offset by a $4 million increase in Base O&M due in part to unplanned maintenance on TEP's generating facilities. Results in the third quarter of 2012 reflect a $2 million reduction to pre-tax income due to an unplanned outage at Springerville Unit 3. See Tucson Electric Power Company, Results of Operations, for more information.

UNS Gas

UNS Gas reported a net loss of $1 million in the third quarter of 2013 compared with no net income or net loss in the third quarter of 2012. The decrease in net income is due in part to higher operations and maintenance expense. See UNS Gas, Results of Operations, for more information.

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UNS Electric

UNS Electric reported net income of $5 million in the third quarter of 2013 compared with $6 million in the third quarter of 2012. The decrease in net income was due in part to the loss of an industrial customer in the second half of 2012. See UNS Electric, Results of Operations, for more information.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012

TEP

TEP reported net income of $96 million in the first nine months of 2013 compared with net income of $65 million in the same period of 2012. The increase in net income is due in part to: a $32 million increase in retail margin revenues related to a non-fuel base rate increase that was effective on July 1, 2013 and higher retail kWh sales resulting from favorable weather conditions; a $2 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; and a $6 million decrease in interest expense due in part to a reduction in capital lease obligation balances; partially offset by a $6 million increase in Base O&M due in part to unplanned maintenance on TEP's generating facilities during the first nine months of 2013; and a $3 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

Additionally, TEP's net income in the first nine months of 2013 includes an income tax benefit of $11 million. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated. See Note 6. TEP's year-to-date 2013 results also include additional fuel expense of $3 million related to a one-time credit to customers resulting from the 2013 TEP Rate Order. TEP's results in the first nine months of 2012 reflect a $3 million reduction to pre-tax income due to an unplanned outage at Springerville Unit 3. See Tucson Electric Power Company, Results of Operations, for more information.

UNS Gas

UNS Gas reported net income of $6 million in the first nine months of 2013 compared with net income of $5 million in the same period of 2012. The increase in net income is due primarily to: a $4 million increase in retail margin revenues related to cold weather that contributed to a 9.6% increase in retail therm sales; and a non-fuel base rate increase that was effective in May 2012; partially offset by a $1 million increase in depreciation and amortization expense related to higher net plant in service. See UNS Gas, Results of Operations, for more information.

UNS Electric

UNS Electric reported net income of $11 million in the first nine months of 2013 compared with net income of $14 million in the same period of 2012. The decrease in net income was due in part to the loss of an industrial customer in the second half of 2012. See UNS Electric, Results of Operations, for more information.

Operations and Maintenance Expense

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
UNS Energy Base O&M (Non-GAAP)⁽¹⁾	$	68	$	61	$	208	$	198
Reimbursed Expenses Related to Springerville Units 3 and 4	18		26		49		53
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs⁽²⁾	7		11		21		33
Total UNS Energy O&M (GAAP)	$	93	$	98	$	278	$	284

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


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

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LIQUIDITY AND CAPITAL RESOURCES

UNS Energy Consolidated Liquidity

During 2013, UNS Energy expects its regulated subsidiaries 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, UNS Energy will use, as needed, its revolving credit facility to assist in funding its business activities. The table below provides a summary of the liquidity position of UNS Energy and each of its segments:



Balances at September 30, 2013	Cash and Cash Equivalents		Borrowings under Revolving Credit Facility⁽¹⁾		Amount Available under Revolving Credit Facility
	Millions of Dollars
UNS Energy Stand-Alone	$	3	$	52	$	73
TEP	35		1		199
UNS Gas⁽²⁾	27		—		70
UNS Electric⁽²⁾	4		23		47
Other⁽³⁾	3		N/A		N/A
Total	$	72


⁽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 UNS Energy’s subsidiaries represent the parent company’s main source of liquidity.

Dividends from Subsidiaries

UNS Energy received $20 million in dividends from TEP and $10 million in dividends from each of UNS Gas and UNS Electric during the first nine months of 2013. During the first nine months of 2012, UNS Energy received $20 million in dividends from UNS Gas, $14 million in dividends from Millennium, and $10 million in dividends from UNS Electric.

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. At September 30, 2013, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit.

Access to Revolving Credit Facilities

We have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP Revolving Credit Facility and UNS Gas/UNS Electric Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Gas, and UNS Electric each issue LOCs from time to time to provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs for general corporate purposes.

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

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UNS Energy Consolidated Cash Flows



	Nine Months Ended September 30,
	2013			2012
	Millions of Dollars
Operating Activities	$	305		$	268
Investing Activities	(239		)	(192		)
Financing Activities	(118		)	(2		)
Net Increase (Decrease) in Cash	(52		)	74
Beginning Cash	124			76
Ending Cash	$	72		$	150

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 nine months of 2013, net cash flows from operating activities were $37 million higher than they were in the same period last year. The following items affected the year-over-year change in operating cash flows: an increase in cash receipts from retail sales related to an increase in sales volumes from cold weather during the first three months of 2013, an increase in TEP's PPFAC rate that became effective in April 2012, and a non-fuel base rate increase that became effective on July 1, 2013; an increase in cash receipts from wholesale sales due in part to higher market prices for wholesale power; lower interest paid on capital lease obligations due to a decline in the balance of capital lease obligations; and various timing differences compared with the first nine months of 2012.

Investing Activities

Net cash flows used for investing activities increased $47 million in the first nine months of 2013 compared with the same period last year due in part to a lower return of investments in Springerville lease debt, a decrease in proceeds from a note receivable, and an increase in REC purchases due to an increase in renewable energy PPAs.

Capital Expenditures



	Actual Year-to-Date		Full Year Estimate
	September 30, 2013		2013
	Millions of Dollars
TEP	$	180	$	255
UNS Gas	13		14
UNS Electric	45		52
UNS Energy Consolidated	$	238	$	321

Financing Activities

Net cash flows used for financing activities were $116 million higher in the first nine months of 2013 compared with the same period last year due to: the issuance of $150 million of long-term debt by TEP during the first nine months of 2012; 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. At September 30, 2013, there was $52 million outstanding at a weighted-average interest rate of 1.68%. 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.

At September 30, 2013, we were in compliance with the terms of the UNS Credit Agreement.

Interest Rate Risk

UNS Energy is subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. UNS Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if 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:


•	We entered into new forward energy commitments with minimum payment obligations of $2 million in 2014, $3 million in 2015 and $2 million in 2016. See Note 4.


•	We entered into new forward purchased power commitments with minimum payment obligations of $15 million in 2014 and $6 million in 2015. See Note 4.

•

TEP has a 20-year Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $2 million in 2013, $4 million per year from 2014 through 2017, and approximately $58 million total thereafter. See Note 4.

•

We entered into new purchase agreements to purchase the environmental attributes, or 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 $13 million from $68 million at December 31, 2012, to $81 million at September 30, 2013. PBIs are recoverable through the RES tariff. See Note 4.

•

In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregate purchase price of $46 million, the appraised value, upon the expiration of the lease term in January 2015. In October 2013, TEP elected to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of continuous operating capability, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014. See Note 5.


•	We entered into new gas transportation agreements that will settle through 2023, resulting in an additional commitment of $7 million in 2013, $14 million in each of 2014, 2015, and 2016, $15 million in 2017, and $57 million thereafter. See Note 4.


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


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

Dividends on Common Stock

In the first nine months of 2013, UNS Energy paid dividends on Common Stock of $54 million. The following table shows the dividends declared to UNS Energy shareholders for 2013:

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Declaration Date	Record Date	Payment Date	Dividend Amount Per Share of Common Stock
February 25, 2013	March 13, 2013	March 25, 2013	$	0.435
May 2, 2013	June 7, 2013	June 26, 2013	$	0.435
August 2, 2013	September 3, 2013	September 25, 2013	$	0.435

Income Tax Position

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

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

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

Third quarter of 2013 compared with the third quarter of 2012

TEP reported net income of $64 million in the third quarter of 2013 compared with net income of $45 million in the third quarter of 2012. The following factors affected TEP’s results in the third quarter of 2013:


•	a $30 million increase in retail margin revenues due primarily to a non-fuel base rate increase that was effective on July 1, 2013;


•	a $1 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;


•	a $2 million increase in pre-tax income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in the third quarter of 2012; and


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

partially offset by:


•	a $4 million increase in Base O&M due in part to higher unplanned generating plant maintenance expense.

Nine months ended September 30, 2013 compared with nine months ended September 30, 2012

TEP reported net income of $96 million in the first nine months of 2013 compared with net income of $65 million in the first nine months of 2012. The following factors affected TEP’s results in the first nine months of 2013:

•

a $32 million increase in retail margin revenues due to a non-fuel base rate increase that was effective on July 1, 2013 as well as favorable weather during the first nine months of 2013 compared with the same period last year. An increase in Heating Degree Days in the first quarter of 2013 and an increase in Cooling Degree Days during the second and third quarters of 2013 contributed to a 1.1% increase in retail kilowatt-hour (kWh) sales during the first nine months of 2013;


•	a $2 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;


•	a $3 million increase in pre-tax income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in the first nine months of 2012;


•	a $6 million decrease in interest expense due to a reduction in the balance of capital lease obligations; and


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

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partially offset by


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


•	a $6 million increase in Base O&M due in part to higher unplanned generating plant maintenance expense; and


•	a $3 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

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 third quarters of 2013 and 2012:



	Three Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	1,354		1,332		22			1.6	%
Commercial	652		648		4			0.5	%
Industrial	621		616		5			0.9	%
Mining	275		275		—			0.1	%
Other	7		7		—			5.7	%
Total Electric Retail Sales	2,909		2,878		31			1.1	%
Retail Margin Revenues (in Millions):
Residential	$	102	$	89	$	13		14.9	%
Commercial	63		52		11			19.9	%
Industrial	31		27		4			12.1	%
Mining	11		9		2			23.3	%
Other	—		—		—			—	%
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	207		177		30			16.3	%
Fuel and Purchased Power Revenues	94		115		(21		)	(18.4	)%
RES, DSM, and ECA Revenues	11		11		—			(1.0	)%
Total Retail Revenues (GAAP)	$	312	$	303	$	9		2.5	%
Average Retail Margin Rate (Cents / kWh):⁽¹⁾
Residential	7.53		6.67		0.86			12.9	%
Commercial	9.62		8.07		1.55			19.2	%
Industrial	4.92		4.43		0.49			11.1	%
Mining	3.85		3.13		0.72			23.0	%
Other	5.66		5.98		(0.32		)	(5.4	)%
Average Retail Margin Revenue	7.09		6.17		0.92			14.9	%
Average Fuel and Purchased Power Revenue	3.23		4.00		(0.77		)	(19.3	)%
Average RES & DSM Revenue	0.36		0.36		—			NM
Total Average Retail Revenue	10.68		10.53		0.15			1.4	%

Weather Data:
Cooling Degree Days
Three Months Ended September 30,	1,042		957		85			8.9	%
10-Year Average	992		990		NM			NM
Wholesale Energy Market Indicators:
Power Prices ($ / MWh)⁽³⁾	$	41.21	$	35.85	$	5.36		15.0	%
Natural Gas Prices ($ / MMBtu) ⁽⁴⁾	$	3.45	$	2.78	$	0.67		24.1	%

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

⁽²⁾

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


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


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

Residential

Residential kWh sales were 1.6% higher in the third quarter of 2013 than they were during the same period last year due in part to an increase in Cooling Degree Days. The higher sales volumes combined with a non-fuel base rate increase effective July 1, 2013 led to an increase in residential margin revenues of 14.9%, or $13 million. Residential use per customer increased by 0.8% due in part to warmer weather. The average number of residential customers grew by 0.8% in the third quarter of 2013 compared with the same period last year.

Commercial

Commercial kWh sales increased by 0.5% compared with the third quarter of 2012 due in part to more Cooling Degree Days than last year. The higher sales combined with a non-fuel base rate increase effective July 1, 2013 lead to an increase in commercial margin revenues of 19.9%, or $11 million.

Industrial

Industrial kWh sales increased by 0.9% compared with the third quarter of 2012, and industrial margin revenues increased by 12.1%, or $4 million when compared with the same period in 2012. The increase in industrial retail margins primarily resulted from a non-fuel base rate increase effective July 1, 2013.

Mining

Mining kWh sales increased by 0.1% compared with the third quarter of 2012. Margin revenues from mining customers increased by $2 million due in part to a non-fuel base rate increase effective July 1, 2013. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

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The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the first nine months of 2013 and 2012:



	Nine Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	3,149		3,085		64			2.1	%
Commercial	1,702		1,682		20			1.2	%
Industrial	1,638		1,628		10			0.6	%
Mining	803		818		(15		)	(1.7	)%
Other	23		23		—			2.2	%
Total Electric Retail Sales	7,314		7,236		78			1.1	%
Retail Margin Revenues (in Millions):
Residential	$	218	$	202	$	16		7.9	%
Commercial	144		132		12			8.5	%
Industrial	74		71		3			4.7	%
Mining	25		23		2			8.7	%
Other	1		1		—			8.3	%
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	461		429		32			7.6	%
Fuel and Purchased Power Revenues	245		256		(11		)	(4.4	)%
RES, DSM, and ECA Revenues	33		32		1			3.4	%
Total Retail Revenues (GAAP)	$	739	$	717	$	22		3.1	%
Average Retail Margin Rate (Cents / kWh):⁽¹⁾
Residential	6.90		6.53		0.37			5.7	%
Commercial	8.43		7.87		0.56			7.1	%
Industrial	4.53		4.35		0.18			4.1	%
Mining	3.12		2.83		0.29			10.2	%
Other	5.65		5.33		0.32			6.0	%
Average Retail Margin Revenue	6.31		5.93		0.38			6.4	%
Average Fuel and Purchased Power Revenue	3.35		3.54		(0.19		)	(5.4	)%
Average RES & DSM Revenue	0.45		0.44		0.01			2.3	%
Total Average Retail Revenue	10.11		9.91		0.20			2.0	%

Weather Data:
Cooling Degree Days
Nine Months Ended September 30,	1,619		1,523		96			6.3	%
10-Year Average	1,456		1,443		NM			NM
Heating Degree Days
Nine Months Ended September 30,	983		790		193			24.4	%
10-Year Average	867		845		NM			NM
Wholesale Energy Market Indicators:
Power Prices ($ / MWh)⁽³⁾	$	37.16	$	28.91	$	8.25		28.5	%
Natural Gas Prices ($ / MMBtu) ⁽⁴⁾	$	3.57	$	2.46	$	1.11		45.1	%


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

⁽²⁾


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

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

Residential

Residential kWh sales were 2.1% higher in the first nine months of 2013 due in part to favorable weather conditions compared with the same period last year. Higher sales and a non-fuel base rate increase effective July 1, 2013 led to an increase in residential margin revenues of 7.9%, or $16 million. The average number of residential customers grew by 0.7% in the first nine months of 2013 compared with the same period last year.

Commercial

Commercial kWh sales increased by 1.2% compared with the first nine months of 2012. Higher sales and a non-fuel base rate increase effective July 1, 2013 contributed to an increase in commercial margin revenues of 8.5%, or $12 million.

Industrial

Industrial kWh sales increased by 0.6% compared with the first nine months of 2012. Higher sales and a non-fuel base rate increase effective July 1, 2013 lead to an increase in industrial margin revenues of $3 million.

Mining

Mining kWh sales decreased by 1.7% compared with the first nine months of 2012. One of TEP's mining customers performed maintenance on its facilities resulting in a temporary decrease in production. See Factors Affecting Results of Operations, Sales to Mining Customers, below.

Wholesale Sales and Transmission Revenues



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)⁽¹⁾	$	2	$	1	$	5	$	3
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues	4		6		14		15
Total Long-Term Wholesale Revenues	6		7		19		18
Transmission Revenues	4		4		11		12
Short-Term Wholesale Revenues	17		14		61		47
Electric Wholesale Sales (GAAP)	$	27	$	25	$	91	$	77

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

Short-Term Wholesale Revenues

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

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Other Revenues



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
Revenue related to Springerville Units 3 and 4⁽¹⁾	$	27	$	31	$	73	$	74
Other Revenue	7		8		21		22
Total Other Revenue	$	34	$	39	$	94	$	96

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

to TEP related to the operation of these plants.

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

Operating Expenses

Fuel and Purchased Power Expense

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



	Generation and Purchased Power				Fuel and Purchased Power Expense
	Three Months Ended September 30,
	2013		2012		2013			2012
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	2,616		2,577		$	66		$	64
Gas-Fired Generation	329		491		14			23
Renewable Generation	8		10		—			—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		2			1
Total Fuel	2,953		3,078		82			88
Total Purchased Power	875		759		42			28
Transmission and Other PPFAC Recoverable Costs	—		—		5			2
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		(8		)	20
Total Resources	3,828		3,837		$	121		$	138
Less Line Losses and Company Use	(261	)	(242	)
Total Energy Sold	3,567		3,595

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	Generation and Purchased Power				Fuel and Purchased Power Expense
	Nine Months Ended September 30,
	2013		2012		2013			2012
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	7,726		7,247		$	208		$	182
Gas-Fired Generation	747		1,187		34			51
Renewable Generation	31		35		—			—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		5			5
Total Fuel	8,504		8,469		247			238
Total Purchased Power	1,848		1,854		90			62
Transmission and Other PPFAC Recoverable Costs	—		—		8			4
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		(5		)	25
Total Resources	10,352		10,323		$	340		$	329
Less Line Losses and Company Use	(680	)	(669	)
Total Energy Sold	9,672		9,654

Generation

Total generating output increased during the first nine months of 2013 when compared with the same period last year due in part to higher retail kWh sales than the same period last year. Coal-fired generation increased by 6.6% during the first nine months of 2013 when compared with the same period last year due in part to the use of coal to fuel Sundt Unit 4 instead of natural gas.

Purchased Power

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

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
	cents per kWh		cents per kWh
Coal	2.53	2.49	2.70	2.50
Gas	4.35	4.69	4.55	4.31
Purchased Power	4.85	3.63	4.86	3.35
All Sources	3.63	3.28	3.56	3.15

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O&M

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	Millions of Dollars						Millions of Dollars
Base O&M (Non-GAAP)⁽¹⁾	$	57		$	53		$	179		$	173
O&M Recorded in Other Expense	(2		)	(1		)	(6		)	(3		)
Reimbursed Expenses Related to Springerville Units 3 and 4	18			26			49			53
Expenses Related to Customer Funded Renewable Energy and DSM Programs⁽²⁾	6			9			17			25
Total O&M (GAAP)	$	79		$	87		$	239		$	248

⁽¹⁾

Base O&M is a non-GAAP financial measure and should not be considered as an alternative to O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is O&M less reimbursed expenses and expenses related to customer-funded renewable energy and DSM programs, provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business.


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

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 TEP Rate Order

In June 2013, the ACC issued an order (2013 TEP Rate Order) that resolved the rate case filed by TEP in July 2012, which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

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


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


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


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


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


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


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


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

The 2013 TEP Rate Order also approved the following cost recovery mechanisms:

•

A Lost Fixed Cost Recovery mechanism (LFCR) that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to energy efficiency programs and distributed generation. The LFCR rate will be adjusted annually and is subject to ACC approval and a year-over-year cap of 1% of TEP's total retail revenues. TEP expects to file its first LFCR report with the ACC on or before May 15, 2014. That report may include an estimated $2 million to $4 million of unrecovered non-fuel costs incurred during calendar year 2013. We expect the new LFCR rate to become effective on July 1, 2014. TEP’s 2015 LFCR report may include an estimated $6 million to $8 million of unrecovered non-fuel costs incurred during 2014.

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•

An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA will be adjusted annually to recover environmental compliance costs and is subject to ACC approval and a cap of $0.00025 per kWh, which approximates 0.25% of TEP's total retail revenues. TEP expects to file its first ECA report on or before March 1, 2014. That report will include qualified investments and costs to be included in the ECA. TEP expects the new ECA rate to become effective on May 1, 2014. We estimate that the ECA could benefit pre-tax income by less than $1 million in 2014.


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


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

Competition

Retail Electric Competition Rules

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

In May 2013, the ACC voted to commence a process to consider the possibility of opening Arizona to retail electric competition. The first step in the process was to solicit comments on questions raised by the ACC on the potential benefits and risks to Arizona electric customers associated with retail electric competition. In July 2013, various parties, including TEP and UNS Electric, filed comments. TEP and UNS Electric oppose opening Arizona to retail electric competition. Responsive comments from the parties were filed in August 2013. In September 2013, the ACC voted to close the docket and did not take any steps to implement retail electric competition. We cannot predict if the ACC will consider retail electric competition in the future.

Technological Developments and Energy Efficiency

New technological developments and the implementation of Electric EE Standards have reduced 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 energy market, TEP competes with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy.

Coal-Fired Generating Resources

At September 30, 2013, approximately 70% of TEP's generating capacity was fueled by coal (of which 120 MW can be converted to 156 MW of natural gas capacity). Existing and proposed federal environmental regulations, as well potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is evaluating various strategies for reducing the proportion of coal in its fuel mix. TEP's ability to reduce its coal-fired generating capacity will depend on several factors, including, but not limited to:


•	the resolution of the non-binding agreement between the State of New Mexico, the EPA, and PNM as it relates to San Juan (see Note 4);


•	TEP's future ownership interest in Springerville Unit 1 (see Springerville Unit 1, below); and


•	the potential purchase of a combined cycle natural gas plant (see Gila River Generating Station Unit 3, below).

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Springerville Unit 1

TEP leases Unit 1 of the Springerville Generating Station and an undivided one-half interest in certain Springerville Common Facilities (collectively Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that are accounted for as capital leases. The leases expire in January 2015 and include fair market value renewal and purchase options. In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 megawatts (MW) of continuous operating capability.

On August 29, 2013, TEP notified certain owner participants and their lessors that TEP elected to purchase their undivided ownership interests in Springerville Unit 1, at the appraised value upon the expiration of the lease term in January 2015. In total, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregate purchase price of $46 million.

On October 3, 2013, TEP agreed to purchase an additional 10.6% leased interest in Springerville Unit 1 for $20 million, the appraised value, with the purchase scheduled to occur in December 2014. The 10.6% ownership interest represents 41 MW of continuous operating capability.

Upon the close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of continuous operating capability. Due to TEP’s purchase commitments, TEP and UNS Energy expect to record an increase to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets in the aggregate amount of approximately $55 million, of which $39 million is reflected as of September 30, 2013.

TEP does not expect that its final undivided ownership interest in Springerville Unit 1 will exceed 49.5%, or 192 MW of continuous operating capability. TEP is obligated to operate Springerville Unit 1 for the remaining third-party owners following the expiration of the leases.

Gila River Generating Station Unit 3

In August 2013, TEP entered into exclusive negotiations with Entegra Power Group LLC (Entegra) to purchase Unit 3 of the Gila River Generating Station (Gila River Unit 3) located in Gila Bend, Arizona. Gila River Unit 3 is a gas-fired combined cycle unit with a nominal capacity rating of 550 MW. Entegra provided a proposal in response to TEP's request for proposals for generating capacity issued in May 2013. UNS Electric may purchase up to 150 MW of Gila River Unit 3, while TEP would purchase the remaining capacity. See UNS Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3, for more information. See Note 13.

The purchase of Gila River Unit 3, which would replace the forgone coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, would be consistent with TEP's strategy to diversify its generation fuel mix. See Note 4.

Although there can be no assurance that TEP and Entegra will reach agreement on the purchase by TEP of Gila River Unit 3, TEP anticipates that, if such an agreement is reached, definitive purchase and sale agreements would be executed prior to year-end 2013. TEP further anticipates any such purchase would close by year-end 2014 and would be subject to, among other things, the receipt of required regulatory approvals.

Purchased Power and Fuel Adjustment Clause

The 2013 TEP Rate Order approved a new PPFAC rate, effective July 1, 2013, which is a credit to retail customers of 0.14 cents per kWh. This PPFAC rate will be in effect until the rate is reset by the ACC in the second quarter of 2014.

TEP’s new PPFAC rate includes:


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


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

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At September 30, 2013, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $11 million. TEP's previous PPFAC mechanism will continue with certain modifications, including the recovery of the following costs and/or credits: lime costs used to control SO₂ emissions, net of Sulfur Credits received from TEP’s coal suppliers; broker fees; and all of the proceeds from the sale of SO₂ allowances.

TEP estimates that from July 1 to December 31, 2013, approximately $5 million of net lime expense will be recorded in fuel and purchased energy expense and recovered through the PPFAC. Prior to July 1, 2013, lime costs were recorded in O&M expense.

Springerville Units 3 and 4

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	Millions of Dollars						Millions of Dollars
Other Revenues	$	27		$	31		$	73		$	74
Fuel Expense	(2		)	(1		)	(5		)	(5		)
O&M Expense	(18		)	(26		)	(49		)	(53		)
Taxes Other Than Income Taxes	—			—			(1		)	(1		)
Total Pre-Tax Income	$	7		$	4		$	18		$	15

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	Millions of Dollars				Millions of Dollars
Pension Expense Charged to O&M	$	3	$	3	$	8	$	8
Retiree Benefit Expense Charged to O&M	1		1		4		3
Total	$	4	$	4	$	12	$	11

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 wholesale market price of on-peak power.

Navajo Tribal Utility Authority

TEP serves the portion of NTUA's load that is not served from NTUA's allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh. Prior to June 30, 2013, the power sold to NTUA was at a fixed price. In May 2013, TEP amended its contract with NTUA and extended the contract from December 2015 to December 2022.

As a result of the amendment, on July 1, 2013, TEP began receiving monthly capacity payments in exchange for providing 15 MW from July to September (June to September beginning in 2014 and thereafter) and 50 MW for the remainder of each year. Starting in 2016, the July to September capacity increases to 25 MW. Any energy sold above those amounts will be indexed to

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the wholesale market price of natural gas. TEP estimates that sales to NTUA will be approximately 225,000 MWh in 2013 and 2014.

Long-Term Wholesale Margin and Sensitivity

TEP’s margin on long-term wholesale sales was $5 million during the first nine months of 2013 and $3 million during the same period last year.

The average price of on-peak power during the first nine months of 2013 was $37 per MWh. A change of $5 per MWh in the on-peak market price of power for the balance of the year would change 2013 pre-tax income related to the SRP contract by approximately $1 million.

Electric Energy Efficiency Standards

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

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

As part of the 2013 TEP Rate Order, the ACC approved a 2013 calendar year energy efficiency budget of $21 million, which includes a performance incentive of approximately $1 million. The performance incentive could be recognized in 2013 if TEP's DSM programs meet certain requirements. 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. See 2013 TEP Rate Order, above.

Renewable Energy Standard and Tariff

In October 2013, the ACC approved TEP's 2014 RES implementation plan. Under the plan, TEP expects to collect approximately $34 million from retail customers during 2014 to fund: the above market cost of renewable energy purchases; performance based incentives for customer installed distributed generation; a return on and of TEP's investments in company-owned solar projects; and various other program costs. The plan includes approval for a TEP investment of $28 million in 2014 for company-owned solar projects and an additional $12 million in 2015. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $1 million pre-tax in 2014 on company-owned solar investments. TEP expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales and the 2014 target of 4.5%.

Sales to Mining Customers

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

In addition to the mining customers that TEP currently serves, Augusta Resources Corporation filed a plan of operations with the United States Forest Service in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona. The Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line for the construction and ongoing operation of the mine. The state line siting committee approved a Certificate of Environmental Compatibility (CEC) in 2011 for the 138 kV transmission line. In 2012, the ACC finalized the CEC. If the Rosemont Copper Mine is constructed and reaches full production, it would be expected to become TEP's largest retail customer, with TEP serving the mine's estimated load of approximately 85 MW.

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

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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 the TEP Revolving Credit Facility. At September 30, 2013, TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds is 10% on $37 million of bonds and 20% on the other $178 million. During the first nine months of 2013, the average rates paid ranged from 0.06% to 0.25%.

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

Fair Value Measurements

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

LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

The tables below show TEP's net cash flows after capital expenditures and payments on capital lease obligations:



	Nine Months Ended September 30,
	2013			2012
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	254		$	207
Amounts from Statements of Cash Flows:
Less: Capital Expenditures	(180		)	(196		)
Net Cash Flows after Capital Expenditures (Non-GAAP)⁽¹⁾	74			11
Amounts From Statements of Cash Flows:
Less: Payments for Capital Lease Obligations	(100		)	(89		)
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⁾	$	(17	)	$	(59	)



	Nine Months Ended September 30,
	2013			2012
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	254		$	207
Net Cash Flows – Investing Activities (GAAP)	(180		)	(173		)
Net Cash Flows – Financing Activities (GAAP)	(119		)	41
Net Increase (Decrease) in Cash	(45		)	75
Beginning Cash	80			28
Ending Cash	$	35		$	103

Net Cash Flows after Capital Expenditures (Non-GAAP)⁽¹⁾	$	74		$	11
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)⁽¹⁾	(17		)	(59		)

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⁽¹⁾

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

Liquidity Outlook

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

Operating Activities

In the first nine months of 2013, net cash flows from operating activities were $47 million higher than in the first nine months of 2012. The increase was due primarily to: higher cash receipts from retail sales related to a base rate increase that became effective on July 1, 2013, as well as an increase in sales volumes and an increase in TEP's PPFAC rate that became effective in April 2012; and a 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 $7 million in the first nine months of 2013 compared with the same period last year due primarily to: lower proceeds from the investment in lease debt; and an increase in purchases of RECs due to an increase in renewable energy PPAs; partially offset by lower capital expenditures.

TEP’s capital expenditures were $180 million in the first nine months of 2013 compared with $196 million in the same period last year. TEP’s estimated capital expenditures for 2013 are $255 million.

Financing Activities

In the first nine months of 2013, net cash from financing activities was $160 million lower than in the same period in 2012. Financing activities in the first nine months of 2013 included a $20 million dividend payment to UNS Energy and an $11 million increase in payments made on capital lease obligations. Financing activities in the first nine months of 2012 included: the issuance of $150 million of long-term debt; $7 million of repayments of long-term debt; and $10 million of repayments (net of borrowings) under the TEP Revolving Credit Facility.

TEP Mortgage Indenture

Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in Mortgage Bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP (i) requested $423 million in Mortgage Bonds be returned to TEP for cancellation, and (ii) discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured. See Note 5.

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. At September 30, 2013, there were no 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. At September 30, 2013, TEP was in compliance with the terms of the TEP Credit Agreement. See Note 5.

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

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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. At September 30, 2013, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement. See Note 5.

2013 Bond Issuances and Redemptions

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

Capital Lease Obligations

At September 30, 2013, TEP had $299 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	September 30, 2013		Expiration	Renewal/Purchase Option
	Millions of Dollars
Springerville Unit 1⁽¹⁾	$	176	2015	Fair market value purchase option of $478 per kW⁽²⁾
Springerville Coal Handling Facilities	28		2015	Fixed price purchase option of $120 million⁽³⁾
Springerville Common Facilities⁽⁴⁾	95		2017 and 2021	Fixed price purchase option of $106 million⁽³⁾
Total Capital Lease Obligations	$	299


⁽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. TEP elected and agreed to purchase certain interests in the Springerville Unit 1 lease agreements in August and October 2013. See Factors Affecting Results of Operations, Coal-Fired Generating Resources, Springerville Unit 1, above. Also see Note 5.

⁽³⁾

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


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

TEP's capital lease obligation balances decline over time due to the normal capital lease payments made by TEP.

Income Tax Position

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

Contractual Obligations

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


•	TEP entered into new forward purchase power commitments that will settle through 2015. 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 September 30, 2013, TEP's estimated minimum payment obligations for these additional purchases are $14 million in 2014 and $2 million in 2015. See Note 4.

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•	TEP has a 20-year PPA with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $2 million in 2013, $4 million per year from 2014 through 2017, and approximately $58 million total thereafter. See Note 4.

•

TEP is contractually obligated to certain retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In 2013, TEP's total obligation for RES PBIs increased by $12 million from $62 million on December 31, 2012 to $74 million on September 30, 2013. TEP will make required payments over periods ranging from 9 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 4.

•

In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregate purchase price of $46 million, the appraised value, upon the expiration of the lease term in January 2015. In October 2013, TEP agreed to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of continuous operating capability, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014. See Note 5.


•	TEP entered into new gas transportation agreements that will settle through 2018, resulting in an additional commitment of $4 million in 2013, $5 million per year from 2014 through 2017 and $1 million in 2018. See Note 4.

•

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


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

Dividends on Common Stock

TEP paid $20 million in dividends to UNS Energy in the first nine months of 2013 compared with no dividends paid to UNS Energy during the same period in 2012.

TEP can pay dividends to UNS Energy if it maintains compliance with the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement. At September 30, 2013, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement.

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

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported a net loss of $1 million in the third quarter of 2013 compared with no net income or net loss in the third quarter of 2012. In the first nine months of 2013, UNS Gas reported net income of $6 million compared with net income of $5 million in the same period last year. The increase in net income for the nine months ended September 30, 2013 is due primarily to: cold weather in the first quarter, which contributed to a 9.6% increase in retail therm sales in the first nine months of 2013 relative to 2012; and a non-fuel base rate increase that was effective in May 2012.

The table below provides summary financial information for UNS Gas:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
	Millions of Dollars						Millions of Dollars
Gas Revenues	$	18		$	18		$	91	$	90
Other Revenues	—			—			2		3
Total Operating Revenues	18			18			93		93
Purchased Gas Expense	5			8			48		49
Increase (Decrease) to Reflect PGA Recovery Treatment	3			—			1		3
O&M	7			6			19		19
Depreciation and Amortization	2			2			7		6
Taxes Other Than Income Taxes	1			1			3		3
Total Other Operating Expenses	18			17			78		80
Operating Income	—			1			15		13
Interest Expense	2			2			5		5
Income Tax Expense	(1		)	(1		)	4		3
Net Income	$	(1	)	$	—		$	6	$	5

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



	Three Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Gas Retail Sales, Therms (in Millions):
Residential	6		5		1			7.7	%
Commercial	4		4		—			5.6	%
All Other	—		—		—			13.2	%
Total Gas Retail Sales	10		9		1			7.2	%
Negotiated Sales Program (NSP)	8		11		(3		)	(26.6	)%
Total Gas Sales	18		20		(2		)	(10.6	)%
Retail Margin Revenues (in Millions):
Residential	$	6	$	6	$	—		3.4	%
Commercial	2		2		—			—	%
All Other	—		—		—			—	%
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	8		8		—			2.6	%
Transport and NSP	5		5		—			(8.5	)%
Retail Fuel Revenues	5		5		—			4.0	%
Total Gas Revenues (GAAP)	$	18	$	18	$	—		(1.1	)%
Weather Data:
Heating Degree Days
Three Months Ended September 30,	101		54		47			87.0	%
10-Year Average	72		74		NM			NM

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⁽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 third quarter of 2013 increased by 7.2% due in part to a 87.0% increase in Heating Degree Days. The increase in retail therm sales, as well as a Base Rate increase implemented in May 2012, contributed to an increase in retail margin revenues of 2.6%, or less than $1 million, when compared with the third 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.

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



	Nine Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Gas Retail Sales, Therms (in Millions):
Residential	49		44		5			10.6	%
Commercial	21		20		1			6.5	%
All Other	6		5		1			12.4	%
Total Gas Retail Sales	76		69		7			9.6	%
Negotiated Sales Program (NSP)	21		26		(5		)	(17.2	)%
Total Gas Sales	97		95		2			2.3	%
Retail Margin Revenues (in Millions):
Residential	$	29	$	27	$	2		8.6	%
Commercial	8		7		1			8.1	%
All Other	2		1		1			14.3	%
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	39		35		4			8.8	%
DSM Revenue	—		1		(1		)	(14.3	)%
Transport and NSP	13		12		1			7.4	%
Retail Fuel Revenues	39		42		(3		)	(6.5	)%
Total Gas Revenues (GAAP)	$	91	$	90	$	1		1.3	%
Weather Data:
Heating Degree Days
Nine Months Ended September 30,	2,769		2,504		265			10.6	%
10-Year Average	2,715		2,728		NM			NM


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

⁽²⁾

Retail therm sales during the first nine months of 2013 increased by 9.6% due in part to a 10.6% 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 8.8%, or $4 million, compared with the same period in 2012.

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FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

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

Rates

2012 UNS Gas Rate Order

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

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

Purchased Gas Adjustor

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

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

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

In October 2013, the ACC approved an increase to the existing customer PGA credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At September 30, 2013, the PGA bank balance was over-collected by $17 million on a billed-to-customer basis.

Gas Energy Efficiency Standards

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

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

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

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Fair Value Measurements

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

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

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

Cash Flows and Capital Expenditures

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



	Nine Months Ended September 30,
	2013			2012
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	18		$	22
Investing Activities	(12		)	(11		)
Financing Activities	(10		)	(20		)
Net Increase/(Decrease) in Cash	(4		)	(9		)
Beginning Cash	31			38
Ending Cash	$	27		$	29

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

UNS Gas/UNS Electric Revolver

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

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

The UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. At September 30, 2013, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.

Interest Rate Risk

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

Contractual Obligations

In 2013, UNS Gas entered into new forward energy commitments that settle through 2016 at fixed prices per MMBtu. UNS Gas’ minimum payment obligations for these purchases are $2 million in 2014, $3 million in 2015, and $2 million in 2016.

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UNS Gas also entered into revised gas transportation agreements and anticipates that its commitments will increase by $3 million in 2013, $9 million in each year 2014 through 2016, $10 million in 2017 and $56 million thereafter. See Note 4.

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 nine months of 2013 and $20 million during the first nine months of 2012. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

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

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $5 million in the third quarter of 2013 compared with net income of $6 million in the third quarter of 2012. In the first nine months of 2013, UNS Electric reported net income of $11 million compared with net income of $14 million in the same period last year. The decline in net income in both periods is related to the loss of an industrial customer during the fourth quarter of 2012 as well as lower mining sales volumes.

Like TEP, UNS Electric’s operations are typically seasonal in nature, with peak energy demand occurring in the summer months. The table below provides summary financial information for UNS Electric:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013			2012
	Millions of Dollars
Retail Electric Revenues	$	52	$	51		$	130		$	134
Wholesale Electric Revenues	2		5			4			13
Other Revenues	—		—			1			1
Total Operating Revenues	54		56			135			148
Purchased Energy Expense	23		24			59			61
Fuel Expense	3		5			7			9
Transmission Expense	4		3			10			8
Increase (Decrease) to Reflect PPFAC Recovery	1		(2		)	(3		)	1
O&M	7		8			22			23
Depreciation and Amortization Expense	5		5			14			14
Taxes Other Than Income Taxes	1		1			4			4
Total Other Operating Expenses	44		44			113			120
Operating Income	10		12			22			28
Interest Expense	2		2			5			5
Income Tax Expense	3		4			6			9
Net Income	$	5	$	6		$	11		$	14

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



	Three Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Electric Retail Sales, kWh (in Millions):
Residential	287		291		(4		)	(1.2	)%
Commercial	171		172		(1		)	(0.3	)%
Industrial	50		58		(8		)	(14.5	)%
Mining	16		20		(4		)	(18.2	)%
Public Authorities	—		—		—			9.5	%
Total Electric Retail Sales	524		541		(17		)	(3.0	)%

Retail Margin Revenues (in Millions):
Residential	$	11	$	11	$	—		(0.9	)%
Commercial	8		8		—			—	%
Industrial	2		2		—			(17.4	)%
Mining	1		2		(1		)	(50.0	)%
Public Authorities	—		—		—			—
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	22		23		(1		)	(5.8	)%
Fuel and Purchased Power Revenues	28		25		3			13.0	%
RES & DSM Revenues	2		3		(1		)	(37.0	)%
Total Retail Revenues (GAAP)	$	52	$	51	$	1		(100.0	)%
Weather Data:
Cooling Degree Days
Three Months Ended September 30,	1,840		1,969		(129		)	(6.6	)%
10-Year Average	1,975		1,972		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 third quarter of 2013 decreased by 3.0% compared with the same period last year. Sales volumes to mining customers decreased by 18.2% in the third quarter of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Industrial kWh sales decreased by 14.5% due to the loss of a customer in the fourth quarter of 2012. Total Retail Margin Revenues in the third quarter of 2013 were lower when compared to the third quarter of 2012 due in part to one of UNS Electric's mining customers generating a portion of its own electricity and the loss of an industrial customer in the fourth quarter of 2012. See Factors Affecting Results of Operations, Large Customers, below.

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



	Nine Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent⁽¹⁾
Electric Retail Sales, kWh (in Millions):
Residential	678		666		12			1.9	%
Commercial	468		470		(2		)	(0.4	)%
Industrial	141		167		(26		)	(15.3	)%
Mining	46		75		(29		)	(39.4	)%
Public Authorities	1		1		—			12.9	%
Total Electric Retail Sales	1,334		1,379		(45		)	(3.2	)%

Retail Margin Revenues (in Millions):
Residential	$	26	$	25	$	1		1.6	%
Commercial	22		22		—			(0.5	)%
Industrial	6		7		(1		)	(15.9	)%
Mining	3		5		(2		)	(34.0	)%
Public Authorities	—		—		—			—
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	57		59		(2		)	(4.0	)%
Fuel and Purchased Power Revenues	67		67		—			0.9	%
RES & DSM Revenues	6		8		(2		)	(33.7	)%
Total Retail Revenues (GAAP)	$	130	$	134	$	(4	)	(3.4	)%
Weather Data:
Cooling Degree Days
Nine Months Ended September 30,	3,144		3,243		(99		)	(3.1	)%
10-Year Average	3,049		3,073		NM			NM
Heating Degree Days
Nine Months Ended September 30,	1,258		1,117		141			12.6	%
10-Year Average	1,239		1,253		NM			NM


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

⁽²⁾

Total retail kWh sales in the first nine months of 2013 decreased by 3.2% compared with the same period last year. Sales volumes to mining customers decreased by 39.4% in the first nine months of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Industrial kWh sales decreased by 15.3% due to the loss of a customer in the fourth quarter of 2012. Total Retail Margin Revenues in the first nine months of 2013 were lower when compared to the same period last year due in part to one of UNS Electric's mining customers generating a portion of its own electricity and the loss of an industrial customer in the fourth quarter of 2012. See Factors Affecting Results of Operations, Large Customers, below.

FACTORS AFFECTING RESULTS OF OPERATIONS

2012 UNS Electric Rate Case

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


•	an increase in non-fuel retail Base Rates of approximately $3 million;


•	an Original Cost Rate Base (OCRB) of approximately $213 million and a Fair Value Rate Base (FVRB) of approximately $283 million;


•	a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;


•	a 0.50% 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 $70 million); and


•	a capital structure of 52.6% equity and 47.4% long-term debt.

The 2013 UNS Electric Settlement Agreement also includes the following cost recovery mechanisms:

•

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

•

a Transmission Cost Adjustment Mechanism (TCA) that would allow more timely recovery of transmission costs associated with serving retail customers at the level approved by FERC. UNS Electric's proposed Base Rates include a transmission component based on UNS Electric’s current FERC Open Access Transmission Tariff (OATT) rate. The OATT rates are adjusted annually and the TCA will be limited to the recovery (or refund) of costs associated with future changes in UNS Electric’s OATT rate.

Status of Rate Proceeding

Hearings before an ACC administrative law judge were completed in September 2013. The settlement agreement requested that new rates be effective by January 1, 2014. We cannot predict if the 2013 UNS Electric Settlement Agreement will be approved or modified by the ACC.

Gila River Generating Station Unit 3

In August 2013, TEP entered into exclusive negotiations with Entegra to purchase Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW. UNS Electric may purchase up to 150 MW of Gila River Unit 3, while TEP would purchase the remaining capacity. See Tucson Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3, and Note 13 for more information.

Renewable Energy Standard and Tariff

In October 2013, the ACC approved UNS Electric's 2014 RES implementation plan. Under the plan, UNS Electric will collect approximately $6 million from customers during 2014 to fund: the above market cost of renewable energy purchases; incentives for customer installed distributed generation; a return on and of UNS Electric's investments in company-owned solar projects; and various other program costs. The plan includes approval for a UNS Electric investment of $5 in 2014 for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, UNS Electric could earn approximately $1 million pre-tax in 2014 on company-owned solar investments. UNS Electric expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales and the 2014 target of 4.5%.

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.

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

Competition

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

Large Customers

One of UNS Electric's mining customers began generating a portion of its own electricity needs in 2011. Due to UNS Electric's retail rate structure and the customer's peak electric demand, the margin revenues from this customer in 2012 were near the same level as 2011. Another large retail customer closed its operations in UNS Electric's service territory in the fourth quarter of 2012. 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 the UNS Gas/UNS Electric Revolver. 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 the UNS Gas/UNS Electric Revolver.

Fair Value Measurements

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

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

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

Cash Flows and Capital Expenditures

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



	Nine Months Ended September 30,
	2013			2012
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	28		$	39
Investing Activities	(47		)	(22		)
Financing Activities	15			(10		)
Net Increase/(Decrease) in Cash	(4		)	7
Beginning Cash	8			5
Ending Cash	$	4		$	12

Operating Activities

Cash provided by operating activities decreased by $11 million in the first nine months of 2013 compared with the same period in 2012 due to: an $8 million decrease in cash receipts from electric sales (net of fuel and purchased energy costs paid) due in part to a lower PPFAC rate that was effective in June 2012, the loss of an industrial customer and lower mining sales; and a $4 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.

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Investing Activities

UNS Electric had capital expenditures of $45 million in the first nine months of 2013 compared with $24 million in the same period in 2012. The increase is related to a transmission line that is being constructed to increase reliability to UNS Electric's service territory in Nogales, Arizona. UNS Electric estimates total capital expenditures in 2013 of $52 million.

Financing Activities

Cash provided by financing activities at UNS Electric in the first nine months of 2013 increased by $25 million when compared with the same period in 2012. Financing activities in 2013 included $23 million of borrowings under the UNS Gas/UNS Electric Revolver (net of repayments) and a $2 million receipt related to a contribution in aid of construction from a large customer.

UNS Gas/UNS Electric Revolver

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

UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At September 30, 2013, UNS Electric had $23 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 2015 at fixed prices per MWh. UNS Electric’s estimated minimum payment obligations for these purchases are $1 million in 2014 and $4 million in 2015.

Additionally, UNS Electric is contractually obligated to certain 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 at December 31, 2012, to $7 million at September 30, 2013. PBIs are recoverable through the RES tariff. See Note 4.

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

Dividends on Common Stock

In the first nine months of 2013 and 2012, UNS Electric paid dividends of $10 million to UNS Energy, through UES. 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. At September 30, 2013, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Gas/UNS Electric Revolver.

CRITICAL ACCOUNTING ESTIMATES

Plant Asset Depreciable Lives

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

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The FASB issued 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. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors. This guidance will be effective in the first quarter of 2014. We do not expect the adoption of this guidance to have a material impact on our financial condition, results of operations, or cash flows.

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.

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 Part 1, Item 2. Management’s Discussion and Analysis, Tucson Electric Power, Factors Affecting Results of Operations, Long-Term Wholesale Sales, Long-Term Wholesale Margin and Sensitivity.

ITEM 4. – CONTROLS AND PROCEDURES

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

While UNS Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UNS Energy’s or TEP’s internal control over financial reporting during the third 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.

PART II – OTHER INFORMATION

ITEM 1. – LEGAL PROCEEDINGS

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

Springerville Unit 1 Appraisal

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

On April 26, 2012, TEP filed a petition to confirm the appraisal in the United States District Court for the District of Arizona. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for

the leased interests. 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.

On August 29, 2013, TEP notified certain owner participants and their lessors of TEP's election to purchase their undivided ownership interests in Springerville Unit 1, at the appraised value upon the expiration of the lease term in January 2015. Because the owner participants whose leased interests TEP elected to purchase have agreed to sell their interests for amounts equal to the appraised value, TEP dismissed its legal action related to the confirmation of the appraised value. See Part 1, Item 2. - Management's Discussion and Analysis, Tucson Electric Power Company, Factors Affecting Results of Operations, Coal-Fired Generating Resources, Springerville Unit 1, for more information.

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Right of Way Matters

TEP previously reported it was a defendant in a class action filed in February 2009 in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs alleged, among other things, that the rights of way for defendants’ transmission lines on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs were requesting, among other things, that the transmission lines on these lands be removed. In March 2010, the court entered a final judgment dismissing the case. The plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (BIA) in May 2010, appealing the BIA’s decision to grant the rights of way that were the subject of the now-dismissed complaint. In June 2010, the BIA found that the Notice of Appeal failed to meet the minimum filing requirements. In September 2010, the plaintiffs filed new Notices of Appeal concerning the same rights of way. In August 2013, the Interior Board of Indian Appeals dismissed the plaintiffs’ appeal for failure to meet procedural requirements. TEP cannot predict if the plaintiffs will again attempt to appeal the BIA’s decision to grant the rights of way.

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 and our 2013 Form 10-Q for the quarterly period ended June 30, 2013.

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:



	Nine Months Ended September 30, 2013	Twelve Months Ended September 30, 2013
UNS Energy	3.180	2.701
TEP	3.147	2.556

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

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. See Note 4 for more information.



Generating Facility	Estimated Annual O&M Expense		Estimated Capital Expenditures		Regulation (Compliance Date)	Upgrades
	Millions of Dollars
Springerville Units 1 & 2	$	3	$	5	MATS (2015)	Mercury Controls
San Juan Unit 1	1		35		Regional Haze/BART (2016)	SNCRs
Navajo Units 1-3	3		86		MATS (2015) Regional Haze/BART (2030)	Mercury Controls; SCRs; Baghouses
Four Corners Units 4 & 5	3		36		MATS (2015) Regional Haze/BART (2018)	Mercury Controls; SCRs

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 September 30, 2013, TEP owned a 14% undivided interest and leased the remaining 86%. See Part I - Item 2. Tucson Electric Power, Factors Affecting Results of Operations, Coal-Fired Generation Resources, Springerville Unit 1, for more information.

⁽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 natural gas is 156 MW.

Greenhouse Gas Regulation

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

Additionally, the President ordered the EPA to:


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


•	finalize those standards by June 1, 2015; and


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

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

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:	November 6, 2013	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer

		TUCSON ELECTRIC POWER COMPANY
		(Registrant)

Date:	November 6, 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, 2013, formatted in XBRL (Extensible Business Reporting Language):


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


(b)	Notes to Condensed Consolidated Financial Statements.

* Previously filed as indicated and incorporated herein by reference.

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