Edgar Filing: TUCSON ELECTRIC POWER CO

March 31, 2015

December 31, 2014

Power Contracts GWh

Gas Contracts GBtu

TEP 10Q 3.31.2015

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2015

¨ 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 1-5924
TUCSON ELECTRIC POWER COMPANY (Exact name of registrant as specified in its charter)
Arizona (State or other jurisdiction of incorporation or organization)		86-0062700 (I.R.S. Employer Identification No.)
88 East Broadway Boulevard, Tucson, AZ 85701 (Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



Yes x		No ¨

Indicate by check mark whether the registrant 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).



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):



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).



Yes ¨		No x

As of May 4, 2015, Tucson Electric Power Company had 32,139,434 shares of common stock, no par value, outstanding, all of which were held by UNS Energy Corporation.

Table of Contents



Definitions	iii
Forward-Looking Information	v
PART I

Item 1. Financial Statements
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	4
Condensed Consolidated Statements of Cash Flows	5
Condensed Consolidated Statement of Changes in Stockholder's Equity	6
Notes to Condensed Consolidated Financial Statements
Note 1. Nature of Operations and Financial Statement Presentation	7
Note 2. Regulatory Matters	7
Note 3. Related Party Transactions	8
Note 4. Debt and Capital Lease Obligations	9
Note 5. Commitments, Contingencies, and Environmental Matters	11
Note 6. Employee Benefit Plans	16
Note 7. Fair Value Measurements and Derivative Instruments	16
Note 8. Recently Issued Accounting Pronouncements	21
Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Critical Accounting Policies	33
Recently Issued Accounting Pronouncements	33
Item 3. – Quantitative and Qualitative Disclosures about Market Risk	34
Item 4. – Controls and Procedures	34

PART II

Item 1. – Legal Proceedings	35
Item 1A. – Risk Factors	35
Item 5. – Other Information	35
Item 6. – Exhibits	38
Signatures	39
Exhibit Index	40

DEFINITIONS

The abbreviations and acronyms used in the first quarter 2015 Form 10-Q are defined below:



2010 Credit Agreement		The 2010 Credit Agreement consists of a $200 million revolving credit and LOC facility together with an $82 million LOC facility to support tax-exempt bonds
2010 TEP Reimbursement Agreement		Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2013 TEP Rate Order		A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013
2014 Credit Agreement		The 2014 Credit Agreement consists of a $70 million revolving credit commitment; a $130 million term loan commitment portion was terminated upon repayment per the agreement
ACC		Arizona Corporation Commission
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
Cooling Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DG		Distributed Generation
DSM		Demand Side Management
ECA		Environmental Compliance Adjustor
EE		Energy Efficiency
FERC		Federal Energy Regulatory Commission
Fortis		Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners		Four Corners Generating Station
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
kV		Kilo-volt
kWh		Kilowatt-hour(s)
LFCR		Lost Fixed Cost Recovery
LOC		Letter of Credit
MMBtu		Million British thermal units
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Navajo		Navajo Generating Station
PNM		Public Service Company of New Mexico
ppb		Parts per billion
PPFAC		Purchased Power and Fuel Adjustment Clause
Regional Haze Rules		Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
San Juan		San Juan Generating Station
SCR		Selective Catalytic Reduction
SES		Southwest Energy Solutions, Inc.
SJCC		San Juan Coal Company
SNCR		Selective Non-Catalytic Reduction
Springerville		Springerville Generating Station

iii



Springerville Coal Handling Facilities		Coal handling facilities at Springerville used by all four Springerville units
Springerville Coal Handling Facilities Leases		Leases for coal handling facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities		Facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities Leases		Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1		Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases		Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2		Unit 2 of the Springerville Generating Station
Springerville Unit 3		Unit 3 of the Springerville Generating Station
Springerville Unit 4		Unit 4 of the Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sundt		H. Wilson Sundt Generating Station
Sundt Unit 4		Unit 4 of the H. Wilson Sundt Generating Station
TEP		Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Third-Party Owners		Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
Tri-State		Tri-State Generation and Transmission Association, Inc.
UNS Electric		UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy
UNS Energy		UNS Energy Corporation
UNS Energy affiliates		Affiliated subsidiaries of UNS Energy including UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas		UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy

Table of Contents

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Tucson Electric Power (TEP) is 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 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 TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as otherwise may be required by the federal securities laws.

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; changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital costs, reduce generating facility output or accelerate generating facility retirements; regional economic and market conditions which could affect customer growth and energy usage; changes in energy consumption by retail customers; 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; the inability to make additions to our existing high voltage transmission system; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing impact of mandated energy efficiency and distributed generation initiatives; changes to long-term contracts; the cost of fuel and power supplies; ability to obtain coal from our suppliers; cyber attacks or challenges to our information security; and the performance of TEP's generating plants.

Table of Contents

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,			December 31,
	2015			2014
	(Unaudited)
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	5,225,923		$	5,175,148
Utility Plant Under Capital Leases	436,199			667,157
Construction Work in Progress	173,889			109,070
Total Utility Plant	5,836,011			5,951,375
Less Accumulated Depreciation and Amortization	(2,091,266		)	(2,052,216		)
Less Accumulated Amortization of Capital Lease Assets	(286,693		)	(473,969		)
Total Utility Plant—Net	3,458,052			3,425,190

Investments and Other Property	38,428			37,599

Current Assets
Cash and Cash Equivalents	65,348			74,170
Accounts Receivable—Customer	72,702			80,713
Accounts Receivable—Other	15,498			12,808
Unbilled Accounts Receivable	32,069			36,804
Allowance for Doubtful Accounts-Customer	(4,776		)	(4,885		)
Allowance for Doubtful Accounts-Other	(5,521		)	—
Accounts Receivable—Due from Affiliates	4,617			5,382
Materials and Supplies	89,043			86,750
Deferred Income Taxes—Current	98,633			102,006
Fuel Inventory	33,758			36,368
Regulatory Assets—Current	79,380			69,383
Derivative Instruments	248			1,633
Other	25,557			22,848
Total Current Assets	506,556			523,980
Regulatory and Other Assets
Regulatory Assets—Noncurrent	238,018			223,192
Derivative Instruments	520			300
Other Assets	21,341			22,161
Total Regulatory and Other Assets	259,879			245,653
Total Assets	$	4,262,915		$	4,232,422

See Notes to Condensed Consolidated Financial Statements.

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,		December 31,
	2015		2014
	(Unaudited)
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,225,282	$	1,215,779
Capital Lease Obligations	59,958		69,438
Long-Term Debt	1,541,486		1,372,414
Total Capitalization	2,826,726		2,657,631
Current Liabilities
Current Obligations Under Capital Leases	131,428		173,822
Borrowings Under Revolving Credit Facilities	—		85,000
Accounts Payable—Trade	93,682		110,480
Accounts Payable—Due to Affiliates	4,200		2,933
Accrued Taxes Other than Income Taxes	47,482		36,110
Accrued Employee Expenses	20,766		15,679
Regulatory Liabilities—Current	33,308		38,847
Accrued Interest	16,190		21,021
Customer Deposits	20,047		20,339
Derivative Instruments	22,016		18,874
Other	11,168		9,673
Total Current Liabilities	400,287		532,778
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	492,662		491,546
Regulatory Liabilities—Noncurrent	313,062		321,186
Pension and Other Postretirement Benefits	138,585		138,319
Derivative Instruments	7,476		6,288
Other	84,117		84,674
Total Deferred Credits and Other Liabilities	1,035,902		1,042,013
Commitments, Contingencies & Environmental Matters (Note 5)
Total Capitalization and Other Liabilities	$	4,262,915	$	4,232,422

See Notes to Condensed Consolidated Financial Statements.

(Concluded)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended March 31,
	2015			2014
	(Unaudited)
	Thousands of Dollars
Operating Revenues
Electric Retail Sales	$	201,622		$	186,015
Electric Wholesale Sales	41,462			42,084
Other Revenues	30,308			27,414
Total Operating Revenues	273,392			255,513
Operating Expenses
Fuel	70,569			67,630
Purchased Power	30,522			22,615
Transmission and Other PPFAC Recoverable Costs	4,707			3,909
Increase (Decrease) to Reflect PPFAC Recovery Treatment	3,249			(1,730		)
Total Fuel and Purchased Energy	109,047			92,424
Operations and Maintenance	82,645			81,345
Depreciation	34,733			30,811
Amortization	5,562			7,099
Taxes Other Than Income Taxes	13,212			11,835
Total Operating Expenses	245,199			223,514
Operating Income	28,193			31,999
Other Income (Deductions)
Interest Income	29			9
Other Income	622			1,912
Other Expense	(462		)	(2,115		)
Appreciation (Depreciation) in Fair Value of Investments	780			255
Total Other Income (Deductions)	969			61
Interest Expense
Long-Term Debt	14,410			14,240
Capital Leases	1,004			3,921
Other Interest Expense	434			313
Interest Capitalized	(454		)	(924		)
Total Interest Expense	15,394			17,550
Income Before Income Taxes	13,768			14,510
Income Tax Expense	4,339			5,338
Net Income	$	9,429		$	9,172

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended March 31,
	2015		2014
	(Unaudited)
	Thousands of Dollars
Comprehensive Income
Net Income	$	9,429	$	9,172
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(12) and $(346)	14		481
Supplemental Executive Retirement Plan (SERP) Net Loss and Prior Service Cost Amortization, net of income tax (expense) benefit of $(37) and $(15)	60		24
Total Other Comprehensive Income (Loss), Net of Taxes	74		505
Total Comprehensive Income	$	9,503	$	9,677

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three Months Ended March 31,
	2015			2014
	(Unaudited)
	Thousands of Dollars
Net Income	$	9,429		$	9,172
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	34,733			30,811
Amortization Expense	5,562			7,099
Amortization of Deferred Debt-Related Costs included in Interest Expense	716			635
Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue	5,521			—
Use of Renewable Energy Credits for Compliance	7,210			4,844
Deferred Income Taxes	4,339			5,337
Pension and Retiree Expense	4,647			3,412
Pension and Retiree Funding	(2,624		)	(1,657		)
Share-Based Compensation Expense	656			792
Allowance for Equity Funds Used During Construction	(343		)	(1,721		)
LFCR and DSM Revenues	(5,461		)	(6,226		)
Increase (Decrease) to Reflect PPFAC Recovery	3,249			(1,730		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	9,947			16,274
Materials and Fuel Inventory	(4,239		)	(3,182		)
Accounts Payable	(12,046		)	(3,425		)
Interest Accrued	(2,559		)	(3,260		)
Taxes Other Than Income Taxes	11,372			9,948
Other	(2,621		)	(1,809		)
Net Cash Flows – Operating Activities	67,488			65,314
Cash Flows from Investing Activities
Capital Expenditures	(99,291		)	(72,570		)
Purchase of Intangibles—Renewable Energy Credits	(6,325		)	(5,431		)
Purchase of Springerville Unit 1 Lease Assets	(45,753		)	—
CIAC	959			5,746
Other, net	—			1,664
Net Cash Flows—Investing Activities	(150,410		)	(70,591		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	15,000			105,000
Repayments of Borrowings Under Revolving Credit Facility	(100,000		)	(105,000		)
Proceeds from Borrowings Under Term Loan	130,000			—
Repayments of Borrowings Under Term Loan	(130,000		)	—
Proceeds from Issuance of Long-Term Debt	299,019			149,168
Repayments of Long-Term Debt	(130,000		)	—
Payments of Capital Lease Obligations	(8,394		)	(79,737		)
Payment of Debt Issue/Retirement Costs	(2,372		)	(1,471		)
Other, net	847			3
Net Cash Flows—Financing Activities	74,100			67,963
Net Increase (Decrease) in Cash and Cash Equivalents	(8,822		)	62,686
Cash and Cash Equivalents, Beginning of Year	74,170			25,335
Cash and Cash Equivalents, End of Period	$	65,348		$	88,021

See Notes to Condensed Consolidated Financial Statements.

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY



	Common Shares	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
	(Unaudited)
	Amounts in Thousands
Balances at December 31, 2014	32,139	$	1,116,539	$	(6,357	)	$	111,523	$	(5,926	)	$	1,215,779
Net Income							9,429					9,429
Other Comprehensive Income, net of tax									74			74
Balances at March 31, 2015	32,139	$	1,116,539	$	(6,357	)	$	120,952	$	(5,852	)	$	1,225,282

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis), which is a leader in the North American electric and gas utility business.

BASIS OF PRESENTATION

We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP), including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. See Note 2. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the condensed consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the condensed consolidated statements of income. 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 2014 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.

In 2014, following the acquisition of UNS Energy by Fortis, TEP elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2015, we adopted accounting guidance that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows.

NOTE 2. REGULATORY MATTERS

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

COST RECOVERY MECHANISMS

Purchased Power and Fuel Adjustment Clause

The ACC adjusts TEP's Purchased Power and Fuel Adjustment Clause (PPFAC) rate annually each April 1 for the subsequent 12-month period. The ACC approved rates of 0.50 cents per Kilowatt-hours (kWh) for the three months ended March 31, 2015 and 0.14 cents per kWh for the three months ended March 31, 2014. In March 2015, the ACC approved a PPFAC rate for TEP of 0.68 cents per kWh for the period April 2015 through March 2016.

In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. As of March 31, 2015, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

statements as an other operating cash receipt. TEP expects to recover any remaining incremental fuel costs, not reimbursed by insurance, through its PPFAC.

Environmental Compliance Adjustor

The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, including related operating expenses, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP recognized ECA revenues of less than $0.5 million in the first three months of 2015.

Energy Efficiency Standards

TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as an annual performance incentive. In the first three months of 2015, TEP recorded an annual DSM performance incentive of $3 million related to savings realized in 2014 that is included in the Electric Retail Sales line item in the accompanying condensed consolidated statements of income.

Lost Fixed Cost Recovery Mechanism

The Lost Fixed Cost Recovery (LFCR) mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved EE programs and distributed generation (DG) targets. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of the company's total retail revenues.

TEP recorded a regulatory asset and recognized LFCR revenues of $3 million in the first three months of 2015 and $5 million in the first three months of 2014. LFCR revenues are included in the Electric Retail Sales in the accompanying condensed consolidated statements of income.

The ACC approved recovery of $5 million through the LFCR recovery mechanism effective August 2014 for the subsequent 12-month period.

REGULATORY ASSETS

TEP's total regulatory assets, including current and noncurrent assets, increased $25 million at March 31, 2015 from December 31, 2014, primarily due to the reclassification of unamortized leasehold improvement costs upon expiration of the Springerville Unit 1 capital lease in January 2015 that relate to third-party ownership interests. These leasehold improvements, previously recorded in Plant in Service, represent investments TEP made through the end of the lease term to ensure that the Springerville facilities continued providing safe, reliable service to TEP's customers. In its 2013 Rate Case, TEP requested and received ACC authorization to use a 10-year amortization period for leasehold improvements at Springerville Unit 1. TEP owns a 49.5% undivided interest in Springerville Unit 1.

NOTE 3. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, Inc., UNS Energy and its affiliated subsidiaries including Unisource Energy Services, Inc., UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy affiliates). These transactions include sales and purchases of power, common cost allocations, and the provision of corporate and other labor related services.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At March 31, 2015 and December 31, 2014, our balance sheets include the following intercompany balances:



	Balances at
	March 31, 2015		December 31, 2014
	Millions of Dollars
Receivables from Related Parties
UNS Electric	$	4	$	4
UNS Gas	1		1
Total Due from Related Parties	$	5	$	5

Payables to Related Parties
SES	$	3	$	2
UNS Energy	1		—
UNS Electric	—		1
Total Due to Related Parties	$	4	$	3

The following table summarizes related party transactions:



	Three Months Ended March 31,
	2015		2014
	Millions of Dollars
Wholesale Sales - TEP to UNS Electric ⁽¹⁾	$	2	$	—
Control Area Services - TEP to UNS Electric ⁽²⁾	—		1
Common Costs - TEP to UNS Energy Affiliates ⁽³⁾	3		3
Supplemental Workforce - SES to TEP ⁽⁴⁾	4		4
Corporate Services - UNS Energy to TEP ⁽⁵⁾	1		1


⁽¹⁾	TEP sells power to UNS Electric at prevailing market prices.


⁽²⁾	TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement.


⁽³⁾	Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.


⁽⁴⁾	SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable.

⁽⁵⁾

Corporate costs at UNS Energy, such as Fortis management fees, legal fees, and audit fees, are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 81% of UNS Energy's allocated costs. For the three months ended March 31, 2015 these costs included approximately $1 million in Fortis management fees and for the three months ended March 31, 2014 these costs included approximately $1 million in merger related costs.

Share-Based Compensation Expense

In January 2015, UNS Energy established a new share-based compensation plan, referred to as the 2015 Share Unit Plan (the Plan), to promote greater alignment of interests between the senior management of UNS Energy and its subsidiaries and the shareholders of Fortis. TEP recognized less than $1 million of share-based compensation expense under the Plan for the three months ended March 31, 2015. For the three months ended March 31, 2014, TEP recognized less than $1 million of expense under UNS Energy's prior share-based compensation plan.

NOTE 4. DEBT AND CAPITAL LEASE OBLIGATIONS

We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2014 Annual Report on Form 10-K.

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CAPITAL LEASE OBLIGATIONS

Springerville Unit 1 Capital Lease Purchase

In January 2015, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value. With the completion of the lease option purchase, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses. See Note 5.

Springerville Coal Handling Facilities Lease Purchase Commitment

In April 2015, upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, bringing its total ownership of the assets to 100%. With the completion of this purchase, Salt River Project Agricultural Improvement and Power District (SRP) is obligated to purchase a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State Generation and Transmission Association, Inc. (Tri-State) is obligated to either: 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. TEP expects SRP to complete its purchase commitment in the second quarter 2015. Tri-State has until April 2016 to elect an option. At March 31, 2015, no amounts have been recorded on TEP's balance sheet for commitments from either SRP or Tri-State.

UNSECURED BOND ISSUANCES AND REDEMPTIONS

In January 2015, amounts borrowed under the 2014 Credit Agreement term loan portion were used to purchase $130 million aggregate principal amount of unsecured Industrial Development Revenue Bonds (IDRBs) issued in June 2008 by the Industrial Development Authority of Pima County for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.75% and mature in September 2029. TEP did not cancel the purchased bonds and had not remarketed them as of March 31, 2015; therefore, they are not reflected as debt on the balance sheet.

In February 2015, TEP issued and sold $300 million aggregate principal amount of its senior unsecured notes bearing interest at the fixed rate of 3.05% and maturing March 15, 2025. TEP may redeem the notes prior to December 15, 2024, with a make-whole premium plus accrued interest. On or after December 15, 2024, TEP may redeem the notes at par plus accrued interest. Interest on the notes will be payable semi-annually on each March 15 and September 15, beginning September 15, 2015, and at maturity.

In March 2015, TEP used the net proceeds from the sale to repay $215 million of revolving and term loans under its 2014 Credit Agreement and 2010 Credit Agreement. See Credit Agreements below. In April 2015, TEP used the remaining amount to pay a portion of the purchase price for its ownership interests in the Springerville Coal Handling Facilities.

CREDIT AGREEMENTS

2014 Credit Agreement

In March 2015, net proceeds from the sale of senior unsecured notes were used to repay the 2014 Credit Agreement's $70 million outstanding revolver borrowings and $130 million outstanding term loan. The $130 million term loan portion cannot be reborrowed per the terms of the agreement. See Unsecured Bond Issuances and Redemptions above.

As of March 31, 2015, there was $70 million available under the revolving credit facility of the 2014 Credit Agreement. As of May 4, 2015, TEP had nothing available under the 2014 Credit Agreement revolving credit facility.

2010 Credit Agreement

Interest rates and fees under the 2010 Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. With Moody's Investors Service, Inc. (Moody's) increase to TEP's credit rating in February 2015, the interest rate currently in effect on borrowings decreased to LIBOR plus 1.00% for Eurodollar loans or Alternate Base Rate plus 0.00% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million Letter of Credit (LOC) facility decreased to 1.00%.

In March 2015, net proceeds from the sale of senior unsecured notes were used to repay $15 million of revolver borrowings outstanding. See Unsecured Bond Issuances and Redemptions above.

As of March 31, 2015, there was $200 million available under the revolving credit facility of the 2010 Credit Agreement. As of May 4, 2015, TEP had $142 million available under the 2010 Credit Agreement revolving credit facility.

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2010 TEP REIMBURSEMENT AGREEMENT

The 2010 TEP Reimbursement Agreement supports $37 million aggregate principal amount of variable rate tax-exempt bonds and includes fees payable on the aggregate outstanding amount. The rate currently in effect decreased to 0.75% per annum after credit rating upgrade in February 2015.

COVENANT COMPLIANCE

At March 31, 2015, we were in compliance with the terms of our loan and credit agreements.

NOTE 5. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS

In addition to those reported in our 2014 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2015:



	2015		2016		2017		2018		2019		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	1	$	2	$	2	$	2	$	2	$	47	$	56
Purchased Power	30		11		—		—		—		—		41
Total Purchase Commitments	$	31	$	13	$	2	$	2	$	2	$	47	$	97

CONTINGENCIES

Navajo Generating Station Lease Extension

Navajo Generating Station (Navajo) is located on a site that is leased from the Navajo Nation with an initial lease term through 2019. The Navajo Nation signed a lease amendment that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agree to the terms. To become effective, this lease amendment must be signed by all of the participants, approved by the Department of the Interior, and is subject to environmental reviews. TEP owns 7.5% of Navajo. In the first quarter of 2015, TEP recorded additional estimated lease expense of approximately $1 million with the expectation that the lease amendment will become effective. At March 31, 2015, TEP's balance sheet reflects a total liability related to the lease amendment of $3 million recorded in Deferred Credits and Other Liabilities—Other.

Claims Related to Springerville Generating Station Unit 1

On November 7, 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1, 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint. On March 23, 2015, the Third-Party Owners filed a request for rehearing in the FERC Action. On April 7, 2015, TEP filed an answer in response to the request for rehearing. The FERC has not yet ruled on the request for rehearing.

On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners' instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action, and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses. On February 20, 2015, TEP filed a motion to dismiss in the New York Action that requested that the court dismiss various counts of the complaint. On March 20, 2015, the Third-Party Owners filed

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a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the Third-Party Owners instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that TEP has failed to pay the Third-Party Owners approximately $71 million in liquidated damages they allege they are owed (see following paragraph), that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired, that TEP has converted the Third-Party Owners’ water rights and that TEP has been unjustly enriched as a result, and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. On April 20, 2015, TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action.

On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.

On April 20, 2015, TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1. As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015.

TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.

Claims 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.

In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United States District Court of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and San Juan. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

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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. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until June 1, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation. A final consent decree version is currently being circulated for signature by all of the parties.

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP's estimated share of the settlement offer submitted by APS in August 2014 is less than $1 million. 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 costs at this time.

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. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting 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 final 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 at all three mines is expected to be $52 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability recorded was $23 million at March 31, 2015 and $22 million at December 31, 2014.

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

TEP’s PPFAC allows us to pass through final reclamation costs, as a component of fuel cost, to retail 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 and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Discontinued Transmission Project

TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-Kilo-volt (kV) line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using the route, or a portion thereof, to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case.

Performance Guarantees

The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-

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defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. As of March 31, 2015, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements for the San Juan, Navajo, Four Corners and Luna generating facilities expire in 2019 through 2046.

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.

Coal Combustion Residuals Regulations

In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. The additional requirements would apply to lateral expansion of those existing landfills or to any new landfill.

Hazardous Air Pollutant Requirements

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics Standards (MATS) rules, additional emission control equipment would have been required by April 2015. However, TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules. TEP's share of the estimated costs to comply with the MATS rules includes the following:



Estimated Mercury Emissions Control Costs:	Navajo		Springerville⁽¹⁾
	Millions of Dollars
Capital Expenditures	$	1	$	5
Annual O&M Expenses	1		1

⁽¹⁾

Total capital expenditures and annual O&M expenses represent amounts for Springerville Units 1 & 2, with estimated costs split equally between the two units. In January 2015, TEP completed the purchase of 49.5% of Springerville Unit 1. With the completion of the purchase, Third Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

TEP expects Four Corners, Sundt, and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules. A study determined that Four Corners' emission controls are adequate. Therefore, TEP expects no additional capital expenditures or O&M expenses will be incurred to comply. Although expected to be compliant, Sundt would be required to install additional monitoring equipment, at an estimated cost of less than $1 million, to continue to burn coal after the MATS rules become effective.

Regional Haze Rules

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

In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). Complying with BART rules, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. These BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other

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provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.

TEP's estimated costs involved in meeting these rules are:



Estimated NOx Emissions Control Costs:	Navajo⁽¹⁾		San Juan ⁽²⁾		Four Corners⁽³⁾		Sundt⁽⁴⁾
	Millions of Dollars
Capital Expenditures	$	28	$	37	$	44	$	12
Annual O&M Expenses	1		1		2		5-6

⁽¹⁾

In August 2014, the EPA published a final Federal Implementation Plan (FIP) wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾

In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million. Prior to the shutdown of any units at San Juan, PNM, the operator, must first obtain New Mexico Public Regulation Commission approval. At March 31, 2015, the net book value of TEP's share in San Juan Unit 2 was $109 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.


⁽³⁾	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾

In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

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NOTE 6. EMPLOYEE BENEFIT PLANS

Net periodic benefit plan cost includes the following components:



	Pension Benefits						Other Retiree Benefits
	Three Months Ended March 31,
	2015			2014			2015		2014
	Millions of Dollars
Service Cost	$	3		$	2		$	1	$	1
Interest Cost	4			4			1		—
Expected Return on Plan Assets	(6		)	(5		)	—		—
Actuarial Loss Amortization	2			1			—		—
Net Periodic Benefit Cost	$	3		$	2		$	2	$	1

NOTE 7. 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. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, 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.



	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets⁽⁵⁾			Net Amount
	March 31, 2015
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	50		$	50	$	—		$	—		$	—		$	50
Restricted Cash⁽¹⁾	2			2		—			—			—			2
Rabbi Trust Investments⁽²⁾	27			—		27			—			—			27
Energy Contracts - Regulatory Recovery⁽³⁾	1			—		—			1			(1		)	—
Total Assets	80			52		27			1			(1		)	79
Liabilities
Energy Contracts - Regulatory Recovery⁽³⁾	(25		)	—		(13		)	(12		)	1			(24		)
Energy Contracts - Cash Flow Hedge⁽³⁾	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps⁽⁴⁾	(4		)	—		(4		)	—			—			(4		)
Total Liabilities	(30		)	—		(17		)	(13		)	1			(29		)
Net Total Assets (Liabilities)	$	50		$	52	$	10		$	(12	)	$	—		$	50

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	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets⁽⁵⁾			Net Amount
	December 31, 2014
	Millions of Dollars
Assets
Cash Equivalents⁽¹⁾	$	15		$	15	$	—		$	—		$	—		$	15
Restricted Cash⁽¹⁾	2			2		—			—			—			2
Rabbi Trust Investments⁽²⁾	26			—		26			—			—			26
Energy Contracts - Regulatory Recovery⁽³⁾	2			—		—			2			(2		)	—
Total Assets	45			17		26			2			(2		)	43
Liabilities
Energy Contracts - Regulatory Recovery⁽³⁾	(18		)	—		(9		)	(9		)	1			(17		)
Energy Contracts - No Regulatory Recovery⁽³⁾	(1		)	—		—			(1		)	1			—
Energy Contracts - Cash Flow Hedge⁽³⁾	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps⁽⁴⁾	(5		)	—		(5		)	—			—			(5		)
Total Liabilities	(25		)	—		(14		)	(11		)	2			(23		)
Net Total Assets (Liabilities)	$	20		$	17	$	12		$	(9	)	$	—		$	20


⁽¹⁾	Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. 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) entered into to reduce exposure to energy price risk, and, at December 31, 2014, a power sale option. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.


⁽⁴⁾	An Interest Rate Swap valued using an income valuation approach, based on the 6-month London Interbank Offered Rate (LIBOR) is 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.

DERIVATIVE INSTRUMENTS

We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. 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.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

The December 31, 2014 valuation of our power sale option was a function of observable market variables, regional power and gas prices, as well as the ratio between the two, which represents the prevailing market heat rate.

We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no 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.

The inputs and 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 price curves monthly.

Cash Flow Hedges

We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreement expires January 2020. The realized loss recorded to Capital Lease Interest Expense was less than $0.5 million for the three months ended March 31, 2015 and less than $1 million for the three months ended March 31, 2014. The realized loss recorded to Long-Term Debt Interest Expense for three months ended March 31, 2014 was less than $0.5 million. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statements of other comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million.

Energy Contracts - Regulatory Recovery

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC 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 table:



		Three Months Ended March 31,
		2015			2014
	Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities		$	(6	)	$	1

Energy Contracts - No Regulatory Recovery

Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For these contracts that qualify as derivatives, we record unrealized gains and losses in the income statement, unless and until a normal purchase or normal sale election is made. In the first quarter of 2015, TEP made a normal sale election for a three-year sales option contract entered into in December 2014.

Derivative Volumes

At March 31, 2015, we have energy contracts that will settle through the first quarter of 2018. The volumes associated with our energy contracts were as follows:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Level 3 Fair Value Measurements

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



		Fair Value at
	Valuation	March 31, 2015						Range of
	Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Power Contracts	Market approach	$	1	$	(8	)	Market price per MWh	$	23.80		$	37.70

Gas Option Contracts	Option model	—		(5		)	Market price per MMbtu	$	2.34		$	3.22
							Gas volatility	24.15		%	39.91		%
Level 3 Energy Contracts		$	1	$	(13	)

		Fair Value at
	Valuation	December 31, 2014						Range of
	Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Power Contracts	Market approach	$	1	$	(6	)	Market price per MWh	$	22.35		$	39.05

Power Sale Option	Market approach	1		(1		)	Market price per MWh	$	27.75		$	44.94
							Market price per MMbtu	$	2.88		$	4.02

Gas Option Contracts	Option model	—		(4		)	Market price per MMbtu	$	2.72		$	3.26
							Gas volatility	30.8		%	53.29		%
Level 3 Energy Contracts		$	2	$	(11	)

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, that are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, 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 March 31,
	2015			2014
	Millions of Dollars
Balances at December 31	$	(9	)	$	(2	)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(2		)	(1		)
Settlements	(1		)	1
Balances at March 31	$	(12	)	$	(2	)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.

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.

Material adverse changes could trigger credit risk-related contingent features. At March 31, 2015, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $27 million, compared with $21 million at December 31, 2014. At March 31, 2015, TEP had no cash collateral posted and less than $0.5 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $27 million.

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 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 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:



		March 31, 2015				December 31, 2014
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Long-Term Debt	Level 2	$	1,541	$	1,642	$	1,372	$	1,457

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 8. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. The revenue standard requires entities to apply the guidance retrospectively or recognize the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. On April 1, 2015, the FASB proposed to defer the effective date of the revenue recognition standard by one year. Based on the proposed effective date, we will be required to adopt the new guidance for annual and interim periods beginning January 1, 2018; early adoption is permitted for annual and interim periods beginning January 1, 2017. We are in the process of identifying contracts with customers and performance obligations in contracts.

In June 2014, the FASB issued guidance that requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.

In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP does not expect the adoption of this guidance to have an impact on its disclosures.

In January 2015, the FASB issued an accounting standards update that removes the concept of extraordinary items from U.S. GAAP. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. TEP does not expect the adoption of this guidance to impact its results of operations or disclosures.

In February 2015, the FASB issued guidance that amends the current consolidation guidance; the amendment affects both the variable interest entity and voting interest entity consolidation models. This standard is effective beginning January 1, 2016; early adoption is permitted. We are evaluating the impact to our financial statements and disclosures.

In April 2015, the FASB issued guidance which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The amendment is effective for periods beginning January 1, 2016 and will be applied retrospectively; early adoption is permitted. The adoption of this standard is expected to result in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on our balance sheet. TEP’s deferred debt issuance costs associated with long-term debt outstanding totaled $12 million at March 31, 2015 and $11 million at December 31, 2014, of which approximately $1 million is classified as current at each date.

In April 2015, the FASB issued guidance that will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement either as a software license or a service contract. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.

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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 TEP. It includes the following:


•	outlook and strategies;


•	operating results during the first quarter of 2015 compared with the first quarter of 2014;


•	factors affecting our results and outlook;


•	liquidity and capital resources including contractual obligations;


•	critical accounting estimates; and


•	recent accounting pronouncements.

OVERVIEW

Tucson Electric Power Company (TEP) is a vertically integrated, regulated utility that generates, transmits and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona.

Management’s Discussion and Analysis includes financial information prepared in accordance with generally accepted accounting principles (GAAP) in the U.S., as well as certain non-GAAP financial measures. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.

Management’s Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes that appear in Item 1 of this Form 10-Q. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see Forward-Looking Information at the front of this report and Risk Factors in Part 1, Item 1A of our 2014 Form 10-K and in Part II, Item 1A of this report.

References in this report to "we" and "our" are to TEP.

OUTLOOK AND STRATEGIES

TEP's 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:


•	Continuing to focus on our long-term generation resource strategy including shifting from coal to natural gas, renewables, and energy efficiency while providing rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, and leveraging our existing utility infrastructure.

•

Developing strategic responses to new environmental regulations and potential new legislation, including proposed carbon emission standards to reduce greenhouse gas emissions from existing power plants. 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 business and the interests of our customers.


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


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


•	Developing strategic responses to the evolving utility business that includes renewable energy, DG, and EE that protect the financial stability of our business while providing benefits and choices to our customers.

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RESULTS OF OPERATIONS

The following discussion provides the significant items that affected TEP's results of operations for the three month periods ended March 31, 2015 and 2014.

First quarter of 2015 compared with the first quarter of 2014

TEP's reported net income of $9 million in the first quarter of 2015 was unchanged from the first quarter of 2014. The following factors impacted TEP’s 2015 results when compared with the first quarter of 2014. All amounts are presented on an after-tax basis:


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


•	a $2 million increase in depreciation and amortization expenses, resulting primarily from an increase in asset base in the current period; partially offset by


•	a $1 million decrease in Base O&M principally due to a decrease in generation expenses;


•	a $1 million increase in transmission revenues;


•	a $1 million decrease in interest expense, primarily due to a reduction in the balance of capital lease obligations. See Note 5 to the Condensed Consolidated Financial Statements; and


•	a $1 million increase in retail margin revenue.

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Utility Sales and Revenues

The table below provides a summary of retail kWh sales, revenues, and weather data during the first quarter of 2015 and 2014:



	Three Months Ended March 31,				Increase (Decrease)
	2015		2014		Amount			Percent
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	680		668		12			1.8	%
Commercial	434		444		(10		)	(2.3	)%
Industrial	463		471		(8		)	(1.7	)%
Mining	275		279		(4		)	(1.4	)%
Public Authorities	9		9		—			—	%
Total Electric Retail Sales	1,861		1,871		(10		)	(0.5	)%
Retail Margin Revenues (in Millions):
Residential	$	52	$	51	$	1		2.0	%
Commercial	34		34		—			—	%
Industrial	22		22		—			—	%
Mining	9		9		—			—	%
Public Authorities	1		1		—			—	%
Total by Customer Class	118		117		1			0.9	%
LFCR Revenues	3		5		(2		)	NM
DSM Performance Bonus	3		1		2			NM
Total Retail Margin Revenues (Non-GAAP)⁽¹⁾	124		123		1			0.8	%
Fuel and Purchased Power Revenues	66		53		13			24.5	%
RES, DSM, and ECA Revenues	12		10		2			20.0	%
Total Retail Revenues (GAAP)	$	202	$	186	$	16		8.6	%
Average Retail Margin Revenues (Cents / kWh):
Residential	7.65		7.63		0.02			0.3	%
Commercial	7.83		7.66		0.17			2.2	%
Industrial	4.75		4.67		0.08			1.7	%
Mining	3.27		3.23		0.04			1.2	%
Public Authorities	11.11		11.11		—			—	%
Total Average Retail Margin Revenues Excluding LFCR & DSM Performance Bonus	6.34		6.25		0.09			1.4	%
Average LFCR Revenues	0.16		0.27		(0.11		)	NM
Average DSM Performance Bonus Revenues	0.16		0.05		0.11			NM
Total Average Retail Margin Revenues Including LFCR & DSM Performance Bonus	6.66		6.57		0.09			1.4	%
Average Fuel and Purchased Power Revenues	3.55		2.83		0.72			25.4	%
Average RES, DSM, and ECA Revenues	0.64		0.53		0.11			20.8	%
Total Average Retail Revenues	10.85		9.93		0.92			9.3	%

Weather Data:
Heating Degree Days
Three Months Ended March 31,	433		429		4			0.9	%
10-Year Average	743		777		(34		)	(4.4	)%

⁽¹⁾

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 because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales and Lost Fixed Cost Recovery (LFCR) revenues available to cover the non-fuel operating expenses of our core utility business.

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Retail kWh Sales and Margin Revenues

TEP's total retail kWh sales decreased by 0.5% in the first quarter of 2015 due in part to ongoing EE programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $1 million, or 0.8% principally due to a change in the customer mix and additional residential usage.

Wholesale Sales and Transmission Revenues



	Three Months Ended March 31,
	2015		2014
	Millions of Dollars
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)⁽¹⁾	$	1	$	3
Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues	7		5
Total Long-Term Wholesale Revenues	8		8
Transmission Revenues	6		4
Short-Term Wholesale Revenues	27		30
Electric Wholesale Sales (GAAP)	$	41	$	42

⁽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 because it demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business.

Long-Term Wholesale Margin Revenues in the first three months of 2015 were lower when compared with the first three months of 2014 due in part to lower market prices for wholesale power.

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

Other Revenues



	Three Months Ended March 31,
	2015		2014
	Millions of Dollars
Revenue related to Springerville Units 3 and 4⁽¹⁾	$	24	$	21
Other Revenue	6		6
Total Other Revenue	$	30	$	27


⁽¹⁾	Represents revenues and reimbursements from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, 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 its affiliates, 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. See Note 3 to the Condensed Consolidated Financial Statements.

Operating Expenses

Generating Output and Fuel and Purchased Power Expense

Total generating output increased during the first quarter of 2015 when compared with the same period last year due to an unplanned maintenance outage in the first quarter of 2014.

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TEP’s fuel and purchased power expense and energy resources for the quarters ended March 31, 2015 and 2014 are detailed below:



	Generation and Purchased Power				Fuel and Purchased Power Expense
	Three Months Ended March 31,
	2015		2014		2015		2014
	Millions of kWh				Millions of Dollars
Coal-Fired Generation	1,938		2,296		$	55	$	56
Gas-Fired Generation	448		239		14		11
Utility Owned Renewable Generation	23		10		—		—
Fuel Expense for Springerville Units 3 and 4⁽¹⁾	—		—		2		1
Total Generation	2,409		2,545		71		68
Total Purchased Power	789		441		30		22
Transmission and Other PPFAC Recoverable Costs	—		—		5		4
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		3		(2		)
Subtotal	3,198		2,986		$	109	$	92
Less Line Losses and Company Use	(143	)	(169	)
Total Energy Sold	3,055		2,817


⁽¹⁾	Springerville Unit 3 and 4 Fuel Expense is reimbursed by Tri-State and SRP.

The table below summarizes average fuel cost per kWh generated or purchased:



	Three Months Ended March 31,
	2015	2014
	cents per kWh
Coal	2.81	2.42
Gas	3.16	4.61
Purchased Power	3.87	5.13
All Sources	3.46	3.34

O&M

The table below summarizes the items included in O&M expense. Base O&M in the first quarter of 2014 includes merger-related expenses of $1 million.



	Three Months Ended March 31,
	2015		2014
	Millions of Dollars
Base O&M (Non-GAAP)⁽¹⁾	$	62	$	64
O&M Recorded in Other Expense	—		(2		)
Reimbursed Expenses Related to Springerville Units 3 and 4⁽²⁾	17		14
Expenses Related to Customer Funded Renewable Energy and DSM Programs⁽³⁾	4		5
Total O&M (GAAP)	$	83	$	81

⁽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 because it represents the fundamental level of operating and maintenance expense related to our core business.


⁽²⁾	Expenses related to Springerville Units 3 and 4 are reimbursed with corresponding amounts recorded in Other Revenue. The Third-Party Owners’ share of expenses related to Springerville Unit 1 is included in Base O&M.


⁽³⁾	These expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

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The table below summarizes TEP’s pension and other retiree benefit expenses included in Base O&M:



	Three Months Ended March 31,
	2015		2014
	Millions of Dollars
Pension Expense Charged to O&M	$	3	$	2
Retiree Benefit Expense Charged to O&M	1		1
Total	$	4	$	3

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 TEP Rate Order

The 2013 TEP Rate Order, issued by the Arizona Corporation Commission (ACC) and effective July 1, 2013, provided for a non-fuel retail Base Rate increase of $76 million; a 10.0% return on equity, a 5.18% cost of long-term debt, and a 1.42% cost of short term debt, resulting in a weighted average cost of capital of 7.26%.

In addition, there are provisions within the 2013 TEP Rate Order allowing more timely recovery of certain costs through several recovery mechanisms:


•	The LFCR mechanism allows recovery of certain non-fuel costs related to kWh sales lost due to EE programs and DG.


•	The Environmental Compliance Adjustor (ECA) mechanism allows recovery of certain capital carrying costs to comply with government-mandated environmental regulations between rate cases.


•	The DSM and Renewable Energy Standard (RES) surcharges allow for recovery of costs to implement DSM and renewable energy programs that support the ACC's EE Standards.

As required by the 2013 Rate Order, TEP filed a compliance report in July 2014 that outlined its planned purchases of: (i) certain ownership interests in Springerville Unit 1; (ii) 75% of Unit 3 of the Gila River Generating Station (Gila River Unit 3); and (iii) the Springerville Coal Handling Facilities. The report estimated that as a result of these purchases, and the termination of certain lease obligations, TEP's 2014 non-fuel revenue requirement would decline by approximately $36 million. However, when other changes to TEP's rate base, expenses and retail sales levels were considered, TEP estimated a non-fuel revenue deficiency of approximately $26 million as of December 31, 2014.

See Note 2 to the Condensed Consolidated Financial Statements for more information.

See Generating Resources and Springerville Coal Handling Facilities Capital Lease Purchase Commitment, below, for more information.

On February 3, 2015, TEP filed a request with the ACC to revise its net metering rates. TEP is proposing a new net metering tariff to ensure that customers who install new rooftop solar power systems pay a more equitable portion of the costs incurred to provide their electric service while still enjoying significant bill savings. TEP is proposing to purchase excess solar output from new rooftop systems at the same price it pays for energy from large local solar arrays rather than providing distributed generation customers with a full retail rate credit.

Generating Resources

At March 31, 2015, approximately 54% of TEP's generating capacity was fueled by coal (Sundt Unit 4 can also be run on natural gas, resulting in 36 MW of additional generating capacity). Existing and proposed federal environmental regulations, as well as potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is executing coal reduction strategies and evaluating additional steps 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:


•	Regulatory approvals associated with the anticipated closure of San Juan Unit 2, and pending ownership restructuring of the remaining units, see Part II, Item. 5 - Other Information, Environmental Matters;


•	The outcome of the proposed Clean Power Plan, see Part II, Item. 5 - Other Information, Environmental Matters;


•	TEP's option to permanently convert Sundt Unit 4 to be fueled by natural gas, see Part II, Item. 5 - Other Information, Environmental Matters;

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•	The ability to resolve Springerville Unit 1 legal proceedings relating to the Third Party Owners, see Note 5 to the Condensed Consolidated Financial Statements.

Springerville Unit 1

TEP leased 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 were accounted for as capital leases. The leases expired in January 2015. At that time, TEP purchased a leased interest comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million. Following this purchase, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity.

The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, is owned by third parties. TEP is not obligated to purchase any of the Third-Party Owners’ generating output. TEP is obligated to operate the unit for the Third-Party Owners. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $2 million per month, and their share of capital expenditures, which are expected to be approximately $8 million in 2015.

As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015. On April 20, 2015, TEP filed a demand for arbitration seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1.

See Note 5 to the Condensed Consolidated Financial Statements for a description of legal proceedings relating to the Third-Party Owners.

Gila River Generating Station Unit 3

On December 10, 2014, TEP and UNS Electric acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW). TEP’s interest in Gila River Unit 3 replaces the expired coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2 and is a key component in TEP's strategy to diversify its generation fuel mix.

Potential Plant Retirements

TEP periodically files an Integrated Resource Plan (IRP) with the ACC. The IRP provides a view of forecasted energy needs over a long term (15 years) and options being considered to meet those needs. TEP's 2014 IRP reflected plans to reduce its overall coal capacity by 492 MW (32% of TEP's existing coal fleet) over the next five years at the Springerville, San Juan, and Sundt Generating Stations. In April 2015, the ACC issued an order to acknowledge TEP's 2014 IRP. TEP's planning assumptions included potentially retiring certain coal-fired generating facilities at San Juan and coal handling facilities at Sundt earlier than their current estimated useful lives. These facilities currently do not have the requisite emission control equipment to meet proposed EPA regulations. TEP continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives, and plans to seek regulatory recovery for amounts that would not be otherwise recovered if and when any assets are retired. See Part II, Item 5. Other Information, Environmental Matters.

Springerville Coal Handling Facilities Capital Lease Purchase Commitment

TEP leased interests in the coal handling facilities at the Springerville Generating Station (Springerville Coal Handling Facilities) under two separate lease agreements (Springerville Coal Handling Facilities Leases). The lease agreements had an initial term that expired in April 2015 and provided TEP the option to renew the leases or to purchase the leased interests at the aggregate fixed price of $120 million. In April 2015, TEP exercised its option to purchase the facilities.

Upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities bringing TEP's total ownership interest to 100%. With the completion of the purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to: 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. TEP expects SRP to complete its purchase commitment in the second quarter 2015. At March 31, 2015, no amounts have been recorded on TEP's balance sheet for commitments from either SRP or Tri-State.

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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 March 31,
	2015			2014
	Millions of Dollars
Other Revenues	$	24		$	21
Fuel Expense	(2		)	(1		)
O&M Expense	(17		)	(14		)

Interest Rates

See Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Fair Value Measurements

See Note 7 to the Condensed Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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 seasonal cash flow, TEP will use its revolving credit facility, as needed, to fund its business activities.

The table below presents net cash provided by (used for) operating, investing and financing activities:



	Three Months Ended March 31,
	2015			2014
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	67		$	65
Net Cash Flows – Investing Activities (GAAP)	(150		)	(70		)
Net Cash Flows – Financing Activities (GAAP)	74			68
Net Increase (Decrease) in Cash	(9		)	63
Beginning Cash	74			25
Ending Cash	$	65		$	88

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



	Three Months Ended March 31,
	2015			2014
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	67		$	65
Less: Capital Expenditures⁽¹⁾	(145		)	(73		)
Net Cash Flows after Capital Expenditures (Non-GAAP)⁽²⁾	(78		)	(8		)
Less: Payments of Capital Lease Obligations	(8		)	(80		)
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)⁽²⁾	$	(86	)	$	(88	)


⁽¹⁾	Includes $46 million related to the purchase of undivided interests in Springerville Unit 1 in January 2015, separately presented on the Statement of Cash Flows.

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⁽²⁾

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 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

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. TEP issued long-term debt in February 2015 to repay revolving and term loans under its credit agreements and to pay a portion of the purchase price for interests in the Springerville Coal Handling Facilities. See Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Operating Activities

In the first three months of 2015, net cash flows from operating activities were $2 million higher than in the same period last year. The increase primarily relates to a $2 million decrease in interest paid, net of amounts capitalized compared with the same period last year.

Investing Activities

Net cash flows used for investing activities increased by $80 million in the first three months of 2015 compared with the same period last year due primarily to a $46 million increase in capital expenditures to purchase an additional 24.8% interests in Springerville Unit 1 for a total ownership interest of 49.5%. Cash flows from investing activities in the first three months of 2015 also included a $27 million increase in capital expenditures to fund system reinforcement through replacements and betterments, primarily the Pinal Central to Tortolita 500kV transmission Line.

Financing Activities

In the first three months of 2015, net cash from financing activities was $6 million higher than the same period last year due to: an increase of $150 million in proceeds from the issuance of long-term debt; the repayment of $130 million in long-term debt; and an $85 million decrease in borrowings (net of repayments) under TEP's revolving credit facilities. Cash flows from financing activities in the first three months of 2015 also reflects a $71 million decrease in payments of capital lease obligations due to the purchase of the remaining undivided interests in Springerville Unit 1.

2015 Unsecured Bond Issuance

In February 2015, TEP issued and sold $300 million of unsecured notes. The bonds bear interest at a fixed rate of 3.05%, and mature in March 2025. TEP may redeem the notes prior to December 15, 2024, with a make-whole premium plus accrued interest. On or after December 15, 2024, TEP may redeem the notes at par plus accrued interest.

In March 2015, TEP used the net proceeds from the sale to repay $215 million of revolving and term loans under its 2014 Credit Agreement and 2010 Credit Agreement. See Credit and Debt Agreements below. In April 2015, TEP used the remaining amount to pay a portion of the purchase price for interest in the Springerville Coal Handling Facilities. See Note 4 to the Condensed Consolidated Financial Statements.

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Credit and Debt Agreements



		At March 31, 2015				As of May 4, 2015
	Expires	Facility Size	LOC Outstanding	Borrowings	Available Balance	Available Balance
		Millions of Dollars
2014 Credit Agreement⁽¹⁾	November 2015
Revolving Credit Facility		70	—	—	70	—
2010 Credit Agreement⁽²⁾	November 2016
Revolving Credit and LOC Facility		200	—	—	200	142
LOC Facility		82	82	—	—	—
Reimbursement Agreement⁽³⁾	February 2019
LOC Facility		37	37	—	—	—

⁽¹⁾

In January 2015, amounts borrowed under the term loan commitment were used to purchase existing Pima County, Arizona unsecured tax-exempt industrial development revenue bonds (IDBs) issued in June 2008 for the benefit of TEP in the amount of $130 million. See Note 4 to the Condensed Consolidated Financial Statements. In March 2015, the $130 million term loan portion of the 2014 Credit Agreement was repaid and cannot be reborrowed.

⁽²⁾

Interest rates and fees under the 2010 Credit Agreement, TEP’s core credit facility, are based on a pricing grid tied to TEP’s credit ratings. In February 2015, Moody's Investors Service, Inc. (Moody's) upgraded the senior unsecured and issuer rating of TEP to A3 from Baa1. The interest rate currently in effect on borrowings is LIBOR plus 1.00% for Eurodollar loans or Alternate Base Rate plus 0.00% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million Letter of Credit (LOC) facility is 1.00%. See Note 4 to the Condensed Consolidated Financial Statements.


⁽³⁾	The LOC supports variable rate tax-exempt pollution control bonds and includes fees payable on the aggregate outstanding amount. The rate currently in effect after Moody's credit upgrade in February 2015 is 0.75% per annum.

Restrictive Debt Covenants

Certain of TEP's credit and debt agreements contain pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings and the amount of fees it pays for its LOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facilities.

The agreements contain restrictions on mergers and sales of assets as well as a maximum leverage test. TEP can pay dividends if it maintains compliance with these restrictions as well as those of the Merger order. The agreements also include conditions of default that would entitle the lenders to accelerate the maturity of all amounts outstanding. At March 31, 2015, TEP was in compliance with all covenants related to its credit agreements and the terms of the Merger order. See Note 4 to the Condensed Consolidated Financial Statements.

Capital Lease Obligations

At March 31, 2015, TEP had $191 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⁽¹⁾	March 31, 2015		Expiration	Renewal/Purchase Option
	Millions of Dollars
Springerville Coal Handling Facilities⁽²⁾	$	117	April 2015	Fixed price purchase option of $120 million
Springerville Common Facilities⁽³⁾	74		2017 and 2021	Fixed price purchase option of $106 million
Total Capital Lease Obligations	$	191


⁽¹⁾	In January 2015, the Springerville Unit 1 leases expired and TEP purchased additional undivided interests in the facility. At March 31, 2015 there is no capital lease obligation balance related to Springerville Unit 1.

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⁽²⁾	The $117 million balance includes the present value at the date of the commitment for the lease purchase options elected in April 2014. In April 2015, the purchase of Springerville Coal Handling Facilities was completed.


⁽³⁾	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.

Contractual Obligations

There have been no changes in TEP's contractual obligations or other commercial commitments from those reported in our 2014 Annual Report on Form 10-K, other than the following changes in 2015:


•	In February 2015, TEP issued and sold $300 million aggregate principal amount of its senior unsecured notes bearing interest at the fixed rate of 3.05% and maturing March 15, 2025. See Note 4 to the Condensed Consolidated Financial Statements.


•	In March 2015, TEP repaid the $130 million term loan under the December 2014 Credit Agreement. See Note 4 to the Condensed Consolidated Financial Statements.

•

In April 2015, upon the expiration of the lease term, TEP purchased its undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million. With the completion of TEP's purchase, SRP has an obligation to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million. TEP expects SRP to complete its purchase commitment in the second quarter of 2015. Tri-State does not have an obligation to purchase the facilities, but by April 2016 Tri-State must elect to either 1) buy a portion of the facilities for $24 million or 2) continue to make payments to TEP for the use of the facilities. See Factors Affecting Results of Operations, Springerville Coal Handling Facilities Capital Lease Purchase Commitment and Note 4 to the Condensed Consolidated Financial Statements.


•	TEP entered into new forward purchased power commitments with minimum payment obligations of $30 million in 2015 and $11 million in 2016. See Note 5 to the Condensed Consolidated Financial Statements.


•	TEP entered into a new gas transportation commitment with minimum payment obligations of $1 million in 2015, $2 million in each of 2016 through 2019, and $47 million in total thereafter through 2039. See Note 5 to the Condensed Consolidated Financial Statements.

We have reviewed our contractual obligations and provide the following additional information:

•

TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of March 31, 2015, TEP had posted less than $1 million in LOCs as collateral with wholesale counterparties for credit enhancement.


•	We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.

Income Tax Position

The 2010 Federal Tax Relief Act, the American Taxpayer Relief Act of 2012, and the Tax Increase Prevention Act of 2014 include provisions that make qualified property placed in service between 2010 and 2014 eligible for 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 TEP otherwise would have received over 20 years and have created net operating loss carryforwards that can be used to offset future taxable income. As a result, TEP did not pay any federal or state income taxes the first three months of 2015 and does not expect to make any payments until 2019.

Dividends on Common Stock

TEP did not pay dividends to UNS Energy in the first three months of 2015 or 2014.

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CRITICAL ACCOUNTING POLICIES

There have been no significant changes in our accounting policies from those disclosed in our 2014 Annual Report on Form 10-K.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, 2014.

ITEM 4. CONTROLS AND PROCEDURES

TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in TEP’s evaluation of its 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 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 TEP in the reports that it files or submits 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, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures are effective as of March 31, 2015.

While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during the first quarter of 2015 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

See the legal proceedings described in Item 3. Legal Proceedings in our 2014 Annual Report on Form 10-K and in Note 5 to the Condensed Consolidated Financial Statements and in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 5 and Item 2 are incorporated herein by reference.

ITEM 1A. RISK FACTORS

The business and financial results of TEP are subject to numerous risks and uncertainties. You should carefully consider the risks and uncertainties reported in our 2014 Annual Report on Form 10-K.

ITEM 5. OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES

The following table reflects the ratio of earnings to fixed charges:



	Three Months Ended March 31, 2015	Twelve Months Ended March 31, 2015
Ratio of Earnings to Fixed Charges	1.541	2.574

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

ENVIRONMENTAL MATTERS

Environmental Regulation

National Ambient Air Quality Standards

In November 2014, the EPA released a proposed rule that would revise the ozone National Ambient Air Quality Standards (NAAQS). The proposal revises the primary and secondary 8-hour NAAQS to within a range of 65-70 parts per billion (ppb), but the EPA is also taking comments on retaining the existing 75 ppb 8-hour standard or adopting an 8-hour standard as low as 60 ppb.

If the standard is ultimately revised below 70 ppb, Pima County and many other parts of Arizona would likely not be able to comply based on current ozone levels. Arizona would then need to submit a plan to meet the revised standard which could potentially limit economic growth in the affected regions. TEP filed comments on the proposed rule urging EPA to retain the existing standard at 75 ppb. The EPA is expected to finalize the rule by October 2015.

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 Mercury and Air Toxics Standards (MATS) rules to set

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the standards for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the final rule, additional emission control equipment would have been required by April 2015. However, TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules.

For more information see Note 5 to the Condensed Consolidated Financial Statements.

Navajo

Based on the MATS rules, Navajo will require mercury control equipment by April 2016. TEP’s share of the estimated capital costs of this equipment is $1 million for mercury control. TEP expects its share of the annual operating costs for mercury control to be $1 million.

San Juan

TEP expects San Juan’s current emission controls to be adequate to comply with the MATS rules.

Four Corners

TEP expects Four Corners' current emission controls to be adequate to comply with the MATS rules.

Springerville Generating Station

Based on the MATS rules, Springerville may require mercury emission control equipment by April 2016. 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 $1 million. Estimated costs are split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015. With the completion of the purchases, Third-Party Owners are responsible for 50.5% of environmental costs attributed to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

Sundt Generating Station

TEP expects the MATS rules will have little effect on capital expenditures at Sundt.

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. BART applies to plants built between August 1962 and August 1977. 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 all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in the units they own at these power plants. TEP cannot predict the ultimate outcome of these matters.

For more information see Note 5 to the Condensed Consolidated Financial Statements.

Navajo

In August 2014, the EPA published the final Regional Haze Federal Implementation Plan (FIP) for Navajo. Among other things, the FIP 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 Selective Catalytic Reduction (SCR) or an equivalent technology on the remaining two units by 2030, and the current owners have to cease their operation of conventional coal-fired generation at Navajo no later than December 22, 2044. The Navajo Nation can continue operation after 2044 at its election. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented.

If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $28 million for the two remaining units. 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

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about $28 million for the two remaining units. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.

San Juan

In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan. The SIP requires the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February of 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million.

In connection with the implementation of the SIP revision and the early retirement of San Juan Units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of the ownership in San Juan, as well as addressing the obligations of the exiting Participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The Participants have engaged a mediator to assist in facilitating the resolution of these matters among the Participants. The Participants of the affected units also may seek approvals of their utility commissions or governing boards. We are unable to predict the outcome of the negotiations and mediation.

Upon the early retirement of San Juan Unit 2, TEP will seek ACC approval to recover any unrecovered cost. TEP's 2013 Rate Case identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. At March 31, 2015, the net book value of TEP's share in San Juan Unit 2 was $109 million.

Four Corners

In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on one unit by October 2016 and the remaining units by October 2017. In December 2013, Arizona Public Service Company (APS), the operator of Four Corners, decided to exercise an option to shut down Units 1, 2, and 3 and install SCRs on Units 4 and 5. Under this scenario, the installation of SCR technology can be delayed until July 2018. TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $44 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 Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018.

Sundt

In June 2014, the EPA issued a final Regional Haze FIP for Arizona including BART requirements for Sundt. The final FIP would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection (DSI) if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. TEP estimates that the cost to install SNCR and DSI would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If retired early, we will request the ACC's approval to recover all the remaining costs of the coal handling facilities.

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.

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In January 2014, the EPA published a re-proposed rule for new power plants. At this time, TEP does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on its operations.

In June 2014, the EPA issued proposed carbon emission regulations for existing power plants called the Clean Power Plan. The Clean Power Plan targets a nation-wide reduction in carbon emissions of 30% by 2030. To achieve this goal, the proposed plan sets carbon emission rates for each state that must be achieved by an interim period of 2020-2029, with final emission rates by 2030. States can apply a variety of strategies to achieve the interim and final emission rates. Using 2012 as a baseline year, Arizona's carbon emission rate for 2030 represents a 52% reduction, most of which would be required by the interim emission rate requirement and could lead to the early retirement of coal generation in Arizona by 2020. The EPA expects to issue a final rule by the summer of 2015, and under the current proposal, states must file implementation plans by June 2016 or June 2017 for multi-state plans. In October 2014, the EPA issued a supplemental proposal regarding carbon emissions regulation impacting the Navajo Nation and the Four Corners and Navajo generating stations which are located on land leased from the Navajo Nation. The regulation, if implemented as proposed, will require carbon reductions on the Navajo Reservation; however, the reduction requirement is less than what is anticipated from unit retirements at the Four Corners and Navajo generating stations associated with Regional Haze requirements. See Regional Haze Rules above.

TEP will continue working with federal and state regulatory authorities, other neighboring utilities, and stakeholders to seek relief from the proposed regulation by reducing the disproportionately high level of carbon emissions reduction for Arizona, and to seek relief from the interim and final proposed compliance requirements. On December 1, 2014, UNS Energy submitted comments on the proposal on behalf of TEP and its other utility subsidiaries. The EPA has received over 3.8 million comments in response to the proposed rule. The proposed rule has been challenged in court and is subject to further legal challenge. TEP cannot predict the ultimate outcome of these matters.

Coal Combustion Residuals Regulations

In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. Additional requirements would apply to lateral expansion of those existing landfills or to any new landfill.

For more information see Note 5 to the Condensed Consolidated Financial Statements.

ITEM 6. EXHIBITS

See Exhibit Index.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




		TUCSON ELECTRIC POWER COMPANY
		(Registrant)

Date:	May 5, 2015	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief
		Financial Officer

EXHIBIT INDEX




12	—	Computation of Ratio of Earnings to Fixed Charges.

31(a)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens.

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

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

101.INS	—	XBRL Instance Document

101.SCH	—	XBRL Taxonomy Extension Schema Document

101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	—	XBRL Taxonomy Extension Definition Linkbase Document



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