10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016

OR

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

For the transition period from                     to                     .

Commission File Number 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
(Former name, former address and former fiscal year, if changed since last report): N/A

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

All shares of outstanding common stock of Tucson Electric Power Company are held by its parent company, UNS Energy Corporation, which is an indirect, wholly-owned subsidiary of Fortis Inc. There were 32,139,434 shares of common stock, no par value, outstanding as of July 28, 2016.

Table of Contents

Definitions	iii
Forward-Looking Information	v
PART I
Item 1. Financial Statements
Condensed Consolidated Statements of Income	1
Condensed Consolidated Statements of Comprehensive Income	2
Condensed Consolidated Statements of Cash Flows	3
Condensed Consolidated Balance Sheets	4
Condensed Consolidated Statements of Changes in Stockholder's Equity	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Critical Accounting Policies and Estimates	39
Accounting Pronouncements	39
Item 3. Quantitative and Qualitative Disclosures about Market Risk	39
Item 4. Controls and Procedures	39
PART II
Item 1. Legal Proceedings	40
Item 1A. Risk Factors	40
Item 5. Other Information	40
Item 6. Exhibits	40
Signatures	41
Exhibit Index	42

ii

DEFINITIONS

The abbreviations and acronyms used in the second quarter2016 Form 10-Q are defined below:

2013 Rate Order	A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013
2015 Credit Agreement	The 2015 Credit Agreement provides for a $250 million revolving credit and letter of credit facility with a letter of credit sublimit of $50 million; the credit agreement matures in 2020
2015 Rate Case	A pending general rate case filed with the ACC by TEP in November 2015 requesting new rates effective January 1, 2017
ACC	Arizona Corporation Commission
APS	Arizona Public Service Company
BART	Best Available Retrofit Technology
Base Rates	The portion of Retail Rates attributed to generation, transmission, distribution, and customer costs. Base Rates exclude authorized charges designed to recover specific costs that are passed through to customers including all fuel and purchased power costs, energy efficiency program costs, certain environmental compliance costs, and a portion of renewable energy costs
Cooling Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DSM	Demand Side Management
EE Standards	Energy Efficiency Standards
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FERC Refund Order	FERC order issued on April 21, 2016, relating to TEP late-filed transmission service agreements, which directs TEP to issue time value refunds to the relevant counterparties to the agreements
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)
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
kWh	Kilowatt-hour(s)
LFCR	Lost Fixed Cost Recovery
LOC	Letter(s) of Credit
MATS	Mercury and Air Toxics Standards
MMBtu	Million British thermal units
MW	Megawatt(s)
MWh	Megawatt-hour(s)
Navajo	Navajo Generating Station
PNM	Public Service Company of New Mexico
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
RES	Renewable Energy Standard
Retail Rates	Rates designed to allow a regulated utility to recover its costs of providing services and an opportunity to earn a reasonable return on its investment
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 Common Facilities	Facilities at Springerville used in common by Springerville Units 1 and 2
Springerville Unit 1 Leases	Leveraged lease arrangements relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
SRP	Salt River Project Agricultural Improvement and Power District
Sundt	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, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
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

iv

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 Company (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, future operational or financial 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, believes, estimates, expects, intends, may, plans, predicts, projects, would, 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 may otherwise 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 estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, 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 I, Item 1A. Risk Factors of our 2015 Form 10-K; Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations; 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 and regulation 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 our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and distributed generation initiatives; changes to long-term contracts; the cost of fuel and power supplies; the ability to obtain coal from our suppliers; cyber attacks or challenges to our information security; and the performance of TEP's generating plants.

v

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Operating Revenues
Retail	$	256,450		$	264,297		$	460,403		$	465,920
Wholesale	34,084			47,674			48,497			89,136
Other	26,950			28,204			52,063			58,512
Total Operating Revenues	317,484			340,175			560,963			613,568
Operating Expenses
Fuel	68,236			77,067			130,914			147,636
Purchased Power	24,023			36,885			41,763			67,407
Transmission and Other PPFAC Recoverable Costs	5,312			6,873			10,490			11,580
Increase (Decrease) to Reflect PPFAC Recovery Treatment	7,470			7,532			14,265			10,781
Total Fuel and Purchased Power	105,041			128,357			197,432			237,404
Operations and Maintenance	86,580			85,655			171,579			168,300
Depreciation	35,913			34,219			71,545			68,952
Amortization	5,545			4,619			11,021			10,181
Taxes Other Than Income Taxes	12,700			12,935			25,730			26,146
Total Operating Expenses	245,779			265,785			477,307			510,983
Operating Income	71,705			74,390			83,656			102,585
Other Income (Deductions)
Interest Income	29			22			67			51
Other Income	1,260			1,436			2,653			2,058
Other Expense	(463		)	(656		)	(886		)	(1,118		)
Appreciation (Depreciation) in Value of Investments	660			(539		)	860			241
Total Other Income (Deductions)	1,486			263			2,694			1,232
Interest Expense
Long-Term Debt	15,486			15,706			30,977			30,116
Capital Leases	855			1,007			1,713			2,012
Other Interest Expense	135			430			258			864
Interest Capitalized	(397		)	(741		)	(861		)	(1,196		)
Total Interest Expense	16,079			16,402			32,087			31,796
Income Before Income Taxes	57,112			58,251			54,263			72,021
Income Tax Expense	16,576			20,425			14,429			24,766
Net Income	$	40,536		$	37,826		$	39,834		$	47,255

The accompanying notes are an integral part of these financial statements.

1

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in thousands)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Comprehensive Income
Net Income	$	40,536	$	37,826	$	39,834	$	47,255
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax (Expense) Benefit of ($81) and ($282)	129		441
Net of Income Tax (Expense) Benefit of ($87) and ($294)					138		455
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax (Expense) Benefit of ($35) and ($38)	57		61
Net of Income Tax (Expense) Benefit of ($70) and ($75)					113		121
Total Other Comprehensive Income (Loss), Net of Tax	186		502		251		576
Total Comprehensive Income	$	40,722	$	38,328	$	40,085	$	47,831

The accompanying notes are an integral part of these financial statements.

2

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)

	Six Months Ended June 30,
	2016			2015
Cash Flows from Operating Activities
Net Income	$	39,834		$	47,255
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	71,545			68,952
Amortization Expense	11,021			10,181
Amortization of Debt Issuance Costs	1,451			1,499
Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue	12,041			11,170
Use of Renewable Energy Credits for Compliance	8,403			12,014
Deferred Income Taxes	14,428			23,835
Pension and Retiree Expense	7,669			9,294
Pension and Retiree Funding	(5,694		)	(9,886		)
Share-Based Compensation Expense	1,244			672
Allowance for Equity Funds Used During Construction	(2,203		)	(1,419		)
FERC Refund Order	10,086			—
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(33,748		)	(44,886		)
Materials, Supplies, and Fuel Inventory	4,151			(3,326		)
Regulatory Assets	(8,579		)	6,183
Accounts Payable and Accrued Charges	11,985			9,590
Regulatory Liabilities	13,588			(7,727		)
Other, Net	(694		)	(4,564		)
Net Cash Flows—Operating Activities	156,528			128,837
Cash Flows from Investing Activities
Capital Expenditures	(135,344		)	(194,915		)
Purchase of Springerville Coal Handling Facilities Lease Assets	—			(120,312		)
Purchase of Springerville Unit 1 Lease Assets	—			(45,753		)
Proceeds from Sale of Springerville Coal Handling Facilities	—			23,656
Purchase of Intangibles - Renewable Energy Credits	(19,570		)	(15,002		)
Contributions in Aid of Construction	(722		)	3,297
Net Cash Flows—Investing Activities	(155,636		)	(349,029		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	—			148,000
Repayments of Borrowings Under Revolving Credit Facilities	—			(233,000		)
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
Repayments of Long-Term Debt	—			(130,000		)
Payments of Capital Lease Obligations	(13,703		)	(12,440		)
Payment of Debt Issue/Retirement Costs	—			(2,920		)
Contribution from Parent	—			180,000
Other, Net	(4,028		)	898
Net Cash Flows—Financing Activities	(17,731		)	249,557
Net Increase (Decrease) in Cash and Cash Equivalents	(16,839		)	29,365
Cash and Cash Equivalents, Beginning of Period	55,684			74,170
Cash and Cash Equivalents, End of Period	$	38,845		$	103,535

The accompanying notes are an integral part of these financial statements.

3

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands)

	June 30,			December 31,
	2016			2015
ASSETS
Utility Plant
Plant in Service	$	5,629,448		$	5,618,435
Utility Plant Under Capital Leases	131,705			131,705
Construction Work in Progress	119,717			102,028
Total Utility Plant	5,880,870			5,852,168
Accumulated Depreciation and Amortization	(2,195,490		)	(2,194,301		)
Accumulated Amortization of Capital Lease Assets	(102,075		)	(99,638		)
Total Utility Plant, Net	3,583,305			3,558,229
Investments and Other Property	40,369			39,569
Current Assets
Cash and Cash Equivalents	38,845			55,684
Accounts Receivable, Net	158,036			136,682
Fuel Inventory	32,184			34,600
Materials and Supplies	91,737			94,003
Regulatory Assets	55,787			51,841
Derivative Instruments	5,019			1,808
Assets Held for Sale, Net	21,550			21,550
Other	17,642			25,904
Total Current Assets	420,800			422,072
Regulatory and Other Assets
Regulatory Assets	213,403			212,312
Derivative Instruments	986			430
Other	34,824			16,866
Total Regulatory and Other Assets	249,213			229,608
Total Assets	$	4,293,687		$	4,249,478

The accompanying notes are an integral part of these financial statements.

(Continued)

4

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands)

	June 30,			December 31,
	2016			2015
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000 Shares Authorized, 32,139 Shares Outstanding at June 30, 2016 and December 31, 2015)	$	1,296,539		$	1,296,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	229,151			189,317
Accumulated Other Comprehensive Loss	(4,313		)	(4,564		)
Total Common Stock Equity	1,515,020			1,474,935
Preferred Stock (No Par Value, 1,000 Shares Authorized, None Outstanding  at June 30, 2016 and December 31, 2015)	—			—
Capital Lease Obligations	39,658			55,324
Long-Term Debt, Net	1,452,396			1,451,720
Total Capitalization	3,007,074			2,981,979
Current Liabilities
Current Obligations Under Capital Leases	15,636			14,114
Accounts Payable	80,292			86,274
Accrued Taxes Other than Income Taxes	39,960			37,577
Accrued Employee Expenses	20,961			27,718
Accrued Interest	14,440			14,246
Regulatory Liabilities	68,474			53,077
Customer Deposits	21,008			20,349
Derivative Instruments	5,513			12,174
Other	22,668			7,533
Total Current Liabilities	288,952			273,062
Regulatory and Other Liabilities
Deferred Income Taxes, Net	479,053			468,024
Regulatory Liabilities	304,512			307,286
Pension and Other Postretirement Benefits	119,126			120,336
Derivative Instruments	2,354			4,067
Other	92,616			94,724
Total Regulatory and Other Liabilities	997,661			994,437
Commitments and Contingencies
Total Capitalization and Other Liabilities	$	4,293,687		$	4,249,478

The accompanying notes are an integral part of these financial statements.

(Concluded)

5

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited)

(Amounts in thousands)

	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances at December 31, 2014	$	1,116,539	$	(6,357	)	$	111,523	$	(5,926	)	$	1,215,779
Net Income						47,255					47,255
Other Comprehensive Income (Loss), Net of Tax								576			576
Contribution from Parent	180,000										180,000
Balances at June 30, 2015	$	1,296,539	$	(6,357	)	$	158,778	$	(5,350	)	$	1,443,610

	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances at December 31, 2015	$	1,296,539	$	(6,357	)	$	189,317	$	(4,564	)	$	1,474,935
Net Income						39,834					39,834
Other Comprehensive Income (Loss), Net of Tax								251			251
Balances at June 30, 2016	$	1,296,539	$	(6,357	)	$	229,151	$	(4,313	)	$	1,515,020

The accompanying notes are an integral part of these financial statements.

6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 419,000 retail 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).

References in these notes to "we" and "our" are to TEP.

BASIS OF PRESENTATION

We prepared our condensed consolidated financial statements according to Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. 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 in 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 and should be read in conjunction with the consolidated financial statements and footnotes in our 2015 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 operating results are not indicative of annual operating results.

Certain amounts from prior periods have been reclassified to conform to the current period presentation.

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.

2015 RATE CASE

In November 2015, TEP filed a general rate case with the ACC based on a test year ended June 30, 2015 (2015 Rate Case). Hearings before an administrative law judge are scheduled to begin in August 2016. The filing requests that new rates be implemented by January 1, 2017.

The key provisions of TEP's general rate case include:

• a Base Rate increase of $110 million, or 12%, compared with adjusted test year revenues;

• a 7.34% return on original cost rate base of $2.1 billion;

• a request to apply excess depreciation reserves against the unrecovered net book value (NBV) of the San Juan Generating Station (San Juan) Unit 2 and the coal handling facilities at the H. Wilson Sundt Generating Station (Sundt) due to early retirement;

• a request for authority to begin using the Third-Party Owners' portion of Springerville Generating Station (Springerville) Unit 1 that is available to TEP for dispatch to serve retail customers' needs and to recover the related operating costs through the Purchased Power and Fuel Adjustment Clause (PPFAC); and

• rate design changes that would reduce the reliance on volumetric sales to recover fixed costs and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service.

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

TEP cannot predict the outcome of this proceeding or whether its rate request will be adopted by the ACC in whole or in part.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.

The table below presents TEP's PPFAC rates approved by the ACC:

Period	Cents per kWh
May 2016 through March 2017 (1)	0.15
April 2015 through April 2016	0.68
October 2014 through March 2015 (2)	0.50

⁽¹⁾  In April 2016, the ACC approved the PPFAC rate adjustment effective May 2016.

⁽²⁾  The ACC approved a new rate effective October 2014.

Renewable Energy Standards

The ACC’s Renewable Energy Standard (RES) requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge until such costs are reflected in TEP’s Base Rates.

In May 2016, the ACC approved TEP's 2016 RES implementation plan that included a budget of $57 million, which will be partially offset by applying approximately $9 million of previously recovered carryover funds. TEP will recover the remaining $48 million through the RES surcharge. The budget will fund the following: (i) the above market cost of renewable energy purchases; (ii) previously awarded performance-based incentives for customer installed distributed generation; (iii) depreciation and a return on TEP's investments in company-owned solar projects; and (iv) various other program costs. The ACC deferred its decision on two proposals related to TEP's utility-owned rooftop solar and community solar projects. As a result, TEP is pursuing approval of these programs and related tariffs in the 2015 Rate Case.

The percentage of retail kilowatt-hour (kWh) sales attributable to the 2015 RES renewable energy requirement was 8.6%, which exceeded the overall 2015 requirement of 5.0%. TEP expects to meet the 2016 requirement of 6.0% of retail kWh sales. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain distributed generation renewable energy credits, which are used to demonstrate compliance with the distributed generation requirement, the company has requested, and the ACC has approved, a waiver of the 2016 residential distributed generation RES incremental requirement. In addition to the 2016 annual waiver, the ACC granted a waiver to TEP for the 2017 calendar year.

Energy Efficiency Standards

TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency Standards (EE Standards). The EE Standards provide for a DSM surcharge for regulated utilities to recover from retail customers the costs to implement DSM programs as well as an annual performance incentive. TEP records its annual DSM performance incentive in the first quarter of each year, with $2 million recorded in 2016 and $3 million in 2015 related to performance in each respective prior calendar year. This performance incentive is included in Retail Revenues on the Condensed Consolidated Statements of Income.

In February 2016, the ACC approved TEP’s 2016 energy efficiency implementation plan. Under the 2016 plan, TEP will recover approximately $14 million from retail customers and will offer customers new and existing DSM programs. Energy savings realized through the programs will count toward the EE Standards and the associated lost revenue will be partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and distributed generation targets. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to file an annual LFCR adjustment request with the ACC to recover the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of TEP's applicable retail revenues.

TEP recorded a regulatory asset and recognized LFCR revenues of $4 million and $9 million in the three and six months ended June 30, 2016, respectively. TEP recorded $3 million and $5 million in the three and six months ended June 30, 2015, respectively. LFCR revenues are included in Retail Revenues on the Condensed Consolidated Statements of Income.

Appellate Review of Rate Decisions

In a 2015 appellate challenge to two ACC rate decisions regarding a water company, the Arizona Court of Appeals considered the issue of how the ACC should determine a utility’s “fair value,” as specified in the Arizona Constitution, in connection with authorizing recovery of costs through rate adjustors outside of a rate case. The Court reversed the ACC’s method of finding fair value in that case and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. In February 2016, the Arizona Supreme Court granted the ACC’s request for review of this decision. In March 2016, the Supreme Court heard oral arguments on this matter. If the Supreme Court upholds the decision without modification, certain TEP rate adjustors may be negatively affected which could have a significant impact on TEP’s ability to recover certain costs between rate cases. TEP filed a brief in support of the ACC’s petition to the Supreme Court for review of the Court of Appeals’ decision, but cannot predict the outcome of this matter.

FERC MATTERS

In April 2016, the FERC issued an order (FERC Refund Order) relating to certain late-filed transmission service agreements (TSAs), which directed TEP to issue time value refunds to the relevant counterparties to these TSAs, in an amount up to $13 million. See Note 5 for additional information related to FERC compliance associated with transmission contracts.

REGULATORY ASSETS AND LIABILITIES

Regulatory assets are either being collected or expected to be collected through Retail Rates. With the exception of the Third-Party Owners' share of the Springerville Unit 1 Leasehold Improvements and Sundt Coal Handling Facilities, we do not earn a return on regulatory assets. Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs, TEP does not pay or accrue a return on regulatory liabilities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

The regulatory assets and liabilities recorded in the Condensed Consolidated Balance Sheets are summarized in the table below:

(in millions)	Remaining Recovery Period (years)	June 30, 2016		December 31, 2015
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	116	$	120
Final Mine Reclamation and Retiree Health Care Costs (1)	21	30		28
Property Tax Deferrals	1	22		21
Income Taxes Recoverable through Future Rates	Various	22		26
Lost Fixed Cost Recovery	1	21		16
Springerville Unit 1 Leasehold Improvements - Third-Party Owners (2)	7	19		21
Sundt Coal Handling Facilities (3)	Plant Life	17		—
Derivatives (Note 8)	3	3		12
Other Regulatory Assets	Various	19		20
Total Regulatory Assets		269		264
Less Current Portion	1	56		52
Total Non-Current Regulatory Assets		$	213	$	212

Regulatory Liabilities
Net Cost of Removal for Interim Retirements (4)	Various	$	263	$	264
Purchased Power and Fuel Adjustment Clause	1	34		18
Deferred Investment Tax Credits	Various	32		32
Renewable Energy Standard	Various	25		25
Other Regulatory Liabilities	Various	19		21
Total Regulatory Liabilities		373		360
Less Current Portion	1	68		53
Total Non-Current Regulatory Liabilities		$	305	$	307

⁽¹⁾  Final Mine Reclamation and Retiree Health Care Costs are recognized at future value. TEP will fully recover these costs through the PPFAC when paid. The majority of our final mine reclamation costs are expected to occur through 2037.

⁽²⁾  Springerville Unit 1 Leasehold Improvements represent investments TEP made, previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10-year amortization period.

⁽³⁾  In June 2014, the Environmental Protection Agency (EPA) issued a final rule that would require TEP to either: (i) install, by mid-2017, Selective Non-Catalytic Reduction (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-Best Available Retrofit Technology (BART) alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered NBV in its 2015 Rate Case.

⁽⁴⁾  Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

NOTE 3. RELATED PARTY TRANSACTIONS

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	June 30, 2016		December 31, 2015
Receivables from Related Parties
UNS Electric	$	4	$	6
UNS Gas	1		1
Total Due from Related Parties	$	5	$	7
Payables to Related Parties
SES	$	2	$	2
UNS Energy	1		2
UNS Electric	—		2
Total Due to Related Parties	$	3	$	6

The following table presents the related party transactions included in the Condensed Consolidated Statements of Income:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Goods and Services Provided by TEP to Affiliates
Transmission Revenues - UNS Electric (1)	$	2	$	2	$	3	$	3
Wholesale Revenues - UNS Electric (1)	—		—		—		1
Control Area Services - UNS Electric (2)	1		—		1		1
Common Costs - UNS Energy Affiliates (3)	4		3		7		6
Goods and Services Provided by Affiliates to TEP
Wholesale Revenues - UNS Electric (1)	$	—	$	—	$	—	$	1
Supplemental Workforce - SES (4)	3		4		7		8
Corporate Services - UNS Energy (5)	2		1		4		2
Corporate Services - UNS Energy Affiliates (6)	2		—		2		—

⁽¹⁾  TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates, through the applicable Open Access Transmission Tariff.

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

⁽³⁾  Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

⁽⁴⁾  SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁵⁾  Costs for corporate services at UNS Energy include Fortis management fees, legal fees, and audit fees which 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 82% of UNS Energy's allocated costs. For the three and six months ended June 30, 2016, these costs included approximately $2 million and $4 million, respectively in Fortis management fees. For the three and six months ended June 30, 2015, Fortis management fees were $1 million and $2 million, respectively.

⁽⁶⁾  Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

DIVIDEND PAID

TEP did not declare or pay dividends in the first six months of 2016 or 2015. On July 27, 2016, TEP declared and paid $20 million in dividends to UNS Energy.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 4. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

There have been no significant changes to our debt, credit facilities, or capital lease obligations from those reported in our 2015 Annual Report on Form 10-K, except as noted below.

CAPITAL LEASE OBLIGATIONS

Springerville Coal Handling Facilities

In April 2015, upon the expiration of the lease term, TEP purchased an undivided ownership interest in the coal handling facilities at Springerville used by all four Springerville units (Springerville Coal Handling Facilities). With the completion of this purchase, Tri-State Generation and Transmission Association, Inc. (Tri-State) was obligated to either: (i) buy a 17.05% undivided interest in the facilities for approximately $24 million; or (ii) continue to make payments to TEP for the use of the facilities. In March 2016, Tri-State notified TEP that it was exercising its option to purchase the undivided interest in the facilities. The Tri-State purchase is expected to close by the end of 2016. At June 30, 2016, Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities is classified as Assets Held for Sale on the Condensed Consolidated Balance Sheets.

COVENANT COMPLIANCE

At June 30, 2016, we were in compliance with the terms of our credit and long-term debt agreements.

NOTE 5. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

In addition to those reported in our 2015 Annual Report on Form 10-K, TEP entered into the following long-term commitments through June 30, 2016:

(in millions)	2016		2017		2018		2019		2020		Thereafter		Total
Fuel, Including Transportation	$	21	$	23	$	24	$	24	$	23	$	22	$	137
Transmission	2		4		4		4		4		3		21
Renewable Power Purchase Agreements	3		3		3		3		3		43		58
Total Purchase Commitments	$	26	$	30	$	31	$	31	$	30	$	68	$	216

TEP's transmission and fuel costs, including transportation, are recoverable from customers through the PPFAC mechanism. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.

Fuel, Including Transportation

TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include price adjustment components that will affect the future cost.

In January 2016, the existing coal sale agreement for San Juan terminated and a new Coal Supply Agreement (CSA) became effective. The new CSA is between San Juan Coal Company (SJCC) and Public Service Company of New Mexico (PNM) and continues through June 2022. TEP is not a party to the new CSA, but has minimum purchase obligations under restructured ownership agreements at San Juan.

In April 2016, Peabody Energy Corp. (Peabody) filed for reorganization under Chapter 11 of the Bankruptcy Code. TEP has existing contracts with Peabody to supply coal from the El Segundo and Lee Ranch mines to Springerville and from the Kayenta mine to Navajo Generating Station (Navajo). TEP has continued to receive its contracted coal as planned and has sufficient access to coal inventory for the near future. TEP cannot currently predict the outcome of this matter or the range of its potential impact on TEP's coal supply from Peabody.

Transmission

TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These contracts expire in various years between 2017 and 2028.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

In June 2016, TEP entered into a new firm point-to-point transmission service agreement. The service agreement has a start date of August 2016 and expires in July 2021.

Renewable Power Purchase Agreements

TEP enters into long-term renewable Power Purchase Agreements (PPA) which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. In March 2016, one of these facilities achieved commercial operation. The PPA expires in February 2036. While TEP is not required to make payments under the agreement if power is not delivered, estimated future payments are included in the table above.

TEP's long-term renewable PPAs effectively transfer commodity price risk to TEP creating a variable interest. TEP has determined it is not a primary beneficiary as it lacks the power to direct the activities that most significantly impact the economic performance of the Variable Interest Entities (VIEs). TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

At June 30, 2016, the carrying amount of assets and liabilities in our Condensed Consolidated Balance Sheets that relate to our variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. Our maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, our exposure is mitigated as we would likely recover these costs through cost recovery mechanisms.

CONTINGENCIES

Legal Matters

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts and are described below.

Claims Related to Springerville Generating Station Unit 1

On February 29, 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). The Agreement provides that: (i) TEP will purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million; and (ii) the Third-Party Owners will pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners. Upon completion of the purchase, all outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners will be dismissed with prejudice.

The purchase of the Third-Party Owners' undivided interest in Springerville Unit 1 is subject to, among other things, approval from the FERC and satisfaction of other customary closing conditions. TEP expects the purchase to close in the third quarter of 2016. However, there is no assurance that the settlement will be finalized or that the litigation will not continue. Therefore, at this time 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 claims, TEP cannot determine estimates of the range of loss, if any, at this time. Should the litigation matters continue, TEP intends to continue vigorously defending itself against the claims asserted by the Third-Party Owners and to continue vigorously pursuing the claims it has asserted against the Owner Trustees and Co-Trustees.

The following is the chronological history of the outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners.

In November 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 existing 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 in January 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. In February 2015, the FERC issued an order denying the Third-Party Owners' complaint. In March 2015, the Third-Party Owners filed a request for rehearing in the FERC Action, which the FERC denied in October 2015. In December 2015, the Third-Party Owners appealed the FERC’s order denying the Third-Party Owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015, TEP filed an unopposed motion to intervene in the Ninth Circuit appeal.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

In December 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). In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged, and the court’s subsequent ruling on the motions, the Third-Party Owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain, and make capital investments in Springerville Unit 1 during the term of the leases and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. The third amended complaint seeks $71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The Third-Party Owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015, the Third-Party Owners filed a motion for summary judgment on their claim that TEP has failed to pay certain of the Third-Party Owners’ claimed expenses.

In December 2014 and January 2015, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent notices to TEP that alleged that TEP had defaulted under the Third-Party Owners’ leases. The notices demanded that TEP pay liquidated damages totaling approximately $71 million. In letters to the Owner Trustees, TEP denied the allegations in the notices.

In April 2015, TEP filed a demand for arbitration with the American Arbitration Association (AAA) seeking an award of the Owner Trustees and Co-Trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015, the Third-Party Owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The Third-Party Owners’ arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the Third-Party Owners’ fees and expenses. TEP and the Third-Party Owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015, the Third-Party Owners filed an amended arbitration demand adding claims that TEP has converted the Third-Party Owners’ water rights and certain emission reduction payments and that TEP is improperly dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. In October 2015, the arbitration panel granted TEP’s motion for interim relief, ordering the Owner Trustees and Co-Trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the Third-Party Owners’ motion for interim relief which had requested that TEP be enjoined from dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling, when economical, the Third-Party Owners’ entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015.

In November 2015, TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming the Owner Trustee and Co-Trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015, the Owner Trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order.

As of June 30, 2016, TEP has billed the Third-Party Owners approximately $35 million for their pro-rata share of Springerville Unit 1 expenses and $7 million for their pro-rata share of capital expenditures, none of which had been paid as of July 28, 2016.

Claims Related to San Juan Generating Station

Bureau of Land Management

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 owns 50% of Units 1 and 2 at 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 predict the final outcome of the BLM’s proposed regulations.

WildEarth Guardians

In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District 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 the OSM. Of the fifteen claims for relief in the WEG

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from the OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against the OSM, including, but not limited to, the 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 the 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 the NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. SJCC was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now proceeding. On July 18, 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM may prepare a new environmental impact statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. The motion also requests that the previously-granted mining plan modification approvals for the San Juan mine remain in effect and mining be allowed to continue during the completion of the EIS, and that the case be dismissed. SJCC joined in the motion. 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.

Claims Related to Four Corners Generating Station

New Mexico Taxation and Revenue Department

In May 2013, the New Mexico Taxation and Revenue Department (NMTRD) issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners Generating Station (Four Corners). TEP's share of the assessment is $1 million based on our ownership percentage. 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. In June 2015, the U.S. District Court for the District of New Mexico ruled in favor of the Four Corners' participants. The NMTRD filed an appeal of the decision in August 2015. In March 2016, the coal supplier at Four Corners reached a final settlement agreement with the NMTRD. TEP's share of the final settlement was less than $1 million.

Endangered Species Act

On April 20, 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Arizona against the OSM and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s (DOI) review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the adjacent Navajo mine. In addition, the lawsuit alleges that these federal agencies violated both the ESA and the NEPA in providing the federal approvals necessary to extend operations at Four Corners and the Navajo mine past July 6, 2016. The lawsuit seeks various forms of relief, including a finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo mine pending compliance with NEPA. The defendants answered the complaint on July 8, 2016. Arizona Public Service Company (APS), the operator of Four Corners, filed a motion to intervene in this matter in July 2016. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Generating Station Lease Amendment

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 in 2013 that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment because certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations between the participants 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 DOI, and is subject to environmental reviews. Once the lease amendment becomes effective, the participants will be responsible for additional lease costs from the date the Navajo Nation signed the lease amendment. TEP owns 7.5% of Navajo. In the first six months of 2016, TEP recorded additional estimated lease expense of $1 million with the expectation that the lease amendment will become effective. TEP's Condensed Consolidated Balance Sheets reflect a total lease amendment liability recorded in Regulatory and Other Liabilities—Other of $4 million at June 30, 2016 and $3 million at December 31, 2015.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Mine Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation mine costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine 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 $42 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. TEP's Condensed Consolidated Balance Sheets reflect a total liability related to reclamation of $24 million at June 30, 2016 and $25 million at December 31, 2015.

Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. 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 mine reclamation costs, as a component of fuel costs, 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.

FERC Compliance

In 2015, TEP self-reported to the FERC Office of Enforcement (OE) that TEP had not timely filed certain FERC-jurisdictional agreements. At that time, TEP conducted a comprehensive internal review of its compliance with the FERC filing requirements (Compliance Review), and made necessary compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TEP TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard form of service agreement. The results of the Compliance Review were reported to OE, which is still reviewing the matter.

In April 2016, the FERC issued the FERC Refund Order relating to the late-filed TSAs, which directs TEP to issue time value refunds to the relevant counterparties to these TSAs, in an amount up to $13 million. In March 2016, as a result of the FERC Refund Order, TEP accrued $13 million offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income. As specified in the FERC Refund Order, TEP reviewed its calculations of the ordered refunds and determined the refund amount to be $3 million, which was paid to the relevant counterparties in June 2016. TEP filed a refund report with the FERC on July 8, 2016. The amount of refunds paid is subject to final approval by the FERC and may be modified if the FERC does not accept TEP’s refund report. The remaining accrued balance is reflected in Current Liabilities—Other at June 30, 2016.

In June 2016, to preserve its rights, TEP petitioned the D.C. Circuit Court of Appeals to review the FERC Refund Order. On July 11, 2016, TEP filed an unopposed motion to hold the appeal in abeyance, which the Court has since granted. The FERC could also impose civil penalties on TEP as a result of the OE's review of the Compliance Review. At this time, TEP cannot predict the outcome of these matters or the range of potential penalties, if any.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and the Luna Energy Facility (Luna). The participants in each of the generating stations, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, the non-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 participant. At June 30, 2016, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046.

Environmental Matters

TEP is subject to federal, state, and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in material compliance with all applicable environmental laws and regulations.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 6. EMPLOYEE BENEFIT PLANS

Net periodic benefit plan cost includes the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	3		$	3		$	1		$	1
Interest Cost	3			4			1			1
Expected Return on Plan Assets	(6		)	(6		)	(1		)	(1		)
Amortization of Net Loss (Gain)	2			2			—			—
Net Periodic Benefit Cost	$	2		$	3		$	1		$	1

	Six Months Ended June 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	6		$	6		$	2		$	2
Interest Cost	7			8			1			2
Expected Return on Plan Assets	(12		)	(12		)	(1		)	(1		)
Amortization of Net Loss (Gain)	4			4			—			—
Net Periodic Benefit Cost	$	5		$	6		$	2		$	3

CONTRIBUTIONS

TEP contributed $2 million in the six months endedJune 30, 2016 to the pension plans and expects to contribute a total of $8 million in 2016.

NOTE 7. SUPPLEMENTAL CASH FLOW INFORMATION

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Six Months Ended June 30,
(in millions)	2016		2015
Accrued Capital Expenditures	$	11	$	23
Net Cost of Removal of Interim Retirements (1)	—		(3		)

⁽¹⁾  The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings.

NOTE 8. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our financial instruments 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.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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.

	Level 1		Level 2			Level 3			Total
(in millions)	June 30, 2016
Assets
Cash Equivalents(1)	$	23	$	—		$	—		$	23
Restricted Cash(1)	4		—			—			4
Energy Derivative Contracts - Regulatory Recovery(2)	—		2			—			2
Energy Derivative Contracts - No Regulatory Recovery(2)	—		—			4			4
Total Assets	27		2			4			33
Liabilities
Energy Derivative Contracts - Regulatory Recovery(2)	—		(4		)	(1		)	(5		)
Interest Rate Swap(3)	—		(3		)	—			(3		)
Total Liabilities	—		(7		)	(1		)	(8		)
Net Total Assets (Liabilities)	$	27	$	(5	)	$	3		$	25

(in millions)	December 31, 2015
Assets
Cash Equivalents(1)	$	33	$	—		$	—		$	33
Restricted Cash(1)	4		—			—			4
Energy Derivative Contracts - Regulatory Recovery(2)	—		1			—			1
Energy Derivative Contracts - No Regulatory Recovery(2)	—		—			1			1
Total Assets	37		1			1			39
Liabilities
Energy Derivative Contracts - Regulatory Recovery(2)	—		(10		)	(3		)	(13		)
Interest Rate Swap(3)	—		(3		)	—			(3		)
Total Liabilities	—		(13		)	(3		)	(16		)
Net Total Assets (Liabilities)	$	37	$	(12	)	$	(2	)	$	23

⁽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 Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property on the Condensed Consolidated Balance Sheets.

⁽²⁾  Energy Contracts include gas swap agreements (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. The valuation techniques are described below.

⁽³⁾  The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We present derivatives on a gross basis in the Condensed Consolidated Balance Sheets. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	June 30, 2016
Derivative Assets
Energy Derivative Contracts	$	6		$	2		$	—	$	4
Derivative Liabilities
Energy Derivative Contracts	(5		)	(2		)	—		(3		)
Interest Rate Swap	(3		)	—			—		(3		)

(in millions)	December 31, 2015
Derivative Assets
Energy Derivative Contracts	$	2		$	1		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(13		)	(1		)	—		(12		)
Interest Rate Swap	(3		)	—			—		(3		)

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.

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.

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 can enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. We have an interest rate swap agreement that expires January 2020. We also had a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement which expired in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The loss expected to be reclassified to earnings withinthe next twelve months is estimated to be $1 million.

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

The realized losses from our cash flow hedges are shown in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Capital Lease Interest Expense	$	—	$	—	$	1	$	1

At June 30, 2016, the total notional amount of our interest rate swap was $23 million.

Energy Derivative Contracts - Regulatory Recovery

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$	12	$	8	$	9	$	2

Energy Derivative 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. The unrealized gains and losses on the long-term power trading contracts are recorded in the income statement, and 10% of any gains will be shared with ratepayers through the PPFAC, as realized.

Derivative Volumes

At June 30, 2016, we have energy contracts that will settle through 2019. The volumes associated with our energy contracts were as follows:

	June 30, 2016	December 31, 2015
Power Contracts GWh	3,832	1,752
Gas Contracts GBtu	13,601	17,214

Level 3 Fair Value Measurements

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

	Valuation	Fair Value of						Range of
	Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
(in millions)	June 30, 2016
Forward Power Contracts	Market approach	$	4	$	(1	)	Market price per MWh	$	21.40	$	36.40
Level 3 Energy Contracts		$	4	$	(1	)

(in millions)	December 31, 2015
Forward Power Contracts	Market approach	$	1	$	(2	)	Market price per MWh	$	19.20		$	31.35
Gas Option Contracts	Option model	—		(1		)	Market price per MMBtu	$	2.17		$	2.69
							Gas volatility	31.0		%	58.3		%
Level 3 Energy Contracts		$	1	$	(3	)

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, 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.

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2016			2015			2016			2015
Beginning of Period	$	(3	)	$	(12	)	$	(2	)	$	(9	)
Gains (Losses) Recorded to: (1)
Regulatory Assets or Liabilities – Derivative Instruments	3			2			2			—
Wholesale Revenues	3			3			3			3
Settlements	—			3			—			2
End of Period	$	3		$	(4	)	$	3		$	(4	)

⁽¹⁾  Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $6 million for both the three months ended June 30, 2016 and 2015 and $6 million and $3 million, for the six months endedJune 30, 2016 and 2015, respectively.

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 TEP and its counterparties 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, or our counterparties, would have to provide certain credit enhancements in the form of cash, a Letter of Credit (LOC), or other acceptable security to collateralize exposure beyond the allowed amounts.

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 June 30, 2016, the value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $15 million, compared with $20 million at December 31, 2015. At June 30, 2016, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on June 30, 2016, TEP would have been required to post an additional $15 million of collateral of which $13 million relates to outstanding net payable balances for settled positions.

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:

• Borrowings under revolving credit facilities 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.

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of our long-term debt:

	Fair Value Hierarchy	Face Value				Fair Value
(in millions)		June 30, 2016		December 31, 2015		June 30, 2016		December 31, 2015
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,466	$	1,466	$	1,541	$	1,529

NOTE 9. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

We consider the applicability and impact of all Accounting Standards Updates issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position, results of operations, or disclosures.

REVENUE FROM CONTRACTS WITH CUSTOMERS

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. In July 2015, the FASB voted to defer the effective date of the revenue recognition standard by one year. We are required to adopt the new guidance for annual and interim periods beginning January 1, 2018.

Retail sales of electricity based on regulator-approved tariff rates represent TEP's primary source of revenue. While it is expected that tariff-based sales to regulated customers are within the scope of the new standard, this question is being reviewed by the AICPA Financial Reporting Executive Committee. TEP is in the process of assessing its performance obligations in its wholesale contracts and identifying other contracts with customers.

CLASSIFICATION AND MEASUREMENT OF FINANCIAL INSTRUMENTS

In January 2016, the FASB amended the guidance on the classification and measurement of financial instruments. Most notably, the new accounting standards update requires the following:

• all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and

• financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset.

TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2018. TEP is evaluating the impact of this guidance to our financial statements and disclosures.

LEASES

In February 2016, the FASB issued an accounting standards update that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under previous GAAP. The standard is effective for periods beginning January 1, 2019 and is to be applied using a modified retrospective approach with practical expedient options; early adoption is permitted. TEP is evaluating the impact of this update to our financial statements and disclosures.

SHARE-BASED COMPENSATION

In March 2016, the FASB issued an accounting standards update that simplifies some provisions in stock compensation accounting. The update involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendment:

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

• requires that all excess tax benefits and tax deficiencies for share-based payment awards be recognized as income tax expense or benefit in the income statement;

• specifies presentation on the statement of cash flows, and

• requires an accounting policy election to estimate the number of awards that are expected to vest or account for forfeitures when they occur.

TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP is evaluating the impact of this update to our financial statements and disclosures.

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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 six months of 2016 compared with the same period of 2015;

• factors affecting our results and outlook;

• liquidity and capital resources including contractual obligations and environmental matters;

• critical accounting policies and estimates; and

• recent accounting pronouncements.

Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP, 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 financial 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 accompanying notes that appear in Part I, 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 2015 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.

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: global, national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include:

• achieving a constructive outcome in our pending rate case proceeding that provides TEP recovery of its full cost of service and an opportunity to earn an appropriate return on its rate base investments, updated rates to provide more accurate price signals and a more equitable allocation of costs to TEP's customers, and enables TEP to continue to provide safe and reliable service.

• 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, optimizing the performance of our existing utility infrastructure, and maintaining financial strength.

• developing strategic responses to new environmental regulations and potential new legislation, including new 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, strengthening our capital structure, sustaining 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.

24

2016 Operational and Financial Highlights

The first six months of 2016 included the following notable items:

• In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase by TEP of the Third-Party Owners' 50.5% undivided interest in Springerville Unit 1 for $85 million. The Third-Party Owners will pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners.

• In March 2016, Tri-State notified TEP that it was exercising its option to purchase a 17.05% undivided interest in the Springerville Coal Handling Facilities for approximately $24 million. The Tri-State purchase is expected to close by the end of 2016.

• In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source as a better-than-BART alternative at Sundt by no later than December 2017.

RESULTS OF OPERATIONS

The following discussion provides the significant items that affected TEP's results of operations during the first six months of 2016 compared with the same period in 2015. The significant items affecting net income are presented on an after-tax basis.

The second quarter of 2016 compared with the second quarter of 2015

TEP reported net income of $41 million in the second quarter2016 compared with $38 million from the second quarter2015. The increase of $3 million, or 7.9%, was primarily due to:

• $3 million in higher net income as a result of a reduction in the valuation allowance for deferred tax assets based on an increase in projected taxable income; and

• $1 million in higher LFCR revenues.

The increase was partially offset by $2 million in higher operations and maintenance expense primarily from increases in maintenance expense due to planned generation outages.

The first six months of2016 compared with the first six monthsof2015

TEP reported net income of $40 million in the first six months of 2016 compared with net income of $47 million from the first six months of 2015. The decrease of $7 million, or 14.9%, was primarily due to:

• $8 million in FERC ordered refunds associated with late-filed TSAs; and

• $5 million in higher operations and maintenance expense resulting primarily from increases in maintenance expense due to planned generation outages, outside services, and employee wages and benefits.

The decrease was partially offset by:

• $3 million in higher net income as a result of a reduction in the valuation allowance for deferred tax assets based on an increase in projected taxable income; and

• $3 million from higher retail sales as a result of favorable weather conditions and an increase in LFCR revenues.

25

Retail Sales and Revenues

Retail Revenues were $256 million in the second quarter of 2016 compared with $264 million in the second quarter of 2015. Retail Margin Revenues (Non-GAAP) were $164 million in the second quarter of 2016 compared with $163 million in the second quarter of 2015. The table below provides a summary of retail kWh sales, a reconciliation of Retail Margin Revenues to Retail Revenues, and weather data for the second quarter of 2016 and 2015:

	Three Months Ended June 30,				Increase (Decrease)
	2016		2015		Amount			Percent
Retail Sales by Customer Class (kWh in millions)
Residential	950		924		26			2.8	%
Commercial	566		564		2			0.4	%
Industrial	494		519		(25		)	(4.8	)%
Mining	247		278		(31		)	(11.2	)%
Public Authorities	7		8		(1		)	(12.5	)%
Total Retail Sales by Class	2,264		2,293		(29		)	(1.3	)%
Retail Revenues (in millions)
Residential	$	72	$	70	$	2		2.9	%
Commercial	51		51		—			—	%
Industrial	26		27		(1		)	(3.7	)%
Mining	9		10		(1		)	(10.0	)%
Public Authorities	1		1		—			—	%
Retail Margin Revenues by Class	159		159		—			—	%
LFCR Revenues	4		3		1			33.3	%
Other Retail Margin Revenues	1		1		—			—	%
Retail Margin Revenues (Non-GAAP) (1)	164		163		1			0.6	%
Fuel and Purchased Power Revenues	79		88		(9		)	(10.2	)%
DSM and RES Surcharge Revenues	13		13		—			—	%
Total Retail Revenues (GAAP)	$	256	$	264	$	(8	)	(3.0	)%
Average Retail Margin Rate by Class (cents / kWh)(2)
Residential	7.58		7.58		—			—	%
Commercial	9.01		9.04		(0.03		)	(0.3	)%
Industrial	5.26		5.20		0.06			1.2	%
Mining	3.64		3.60		0.04			1.1	%
Public Authorities	5.79		5.74		0.05			0.9	%
Average Retail Margin Rate by Class	7.02		6.93		0.09			1.3	%
Total Average Retail Margin Rate (3)	7.24		7.11		0.13			1.8	%
Average Fuel and Purchased Power Rate	3.49		3.84		(0.35		)	(9.1	)%
Average DSM and RES Surcharge Rate	0.57		0.57		—			—	%
Total Average Retail Rate	11.30		11.52		(0.22		)	(1.9	)%
Weather Data
Cooling Degree Days
Actual	469		480		(11		)	(2.3	)%
10-year Average	472		479		*			*
Heating Degree Days
Actual	23		19		4			21.1	%
10-year Average	42		41		*			*

*Not meaningful

26

⁽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, LFCR revenues, DSM performance bonus, and certain other retail margin revenues available to cover the non-fuel operating expenses of our core utility business.

⁽²⁾  Calculated on unrounded data and may not correspond exactly to data shown in table.

⁽³⁾  Total Average Retail Margin Rate includes revenue related to LFCR and Other Retail Margin Revenues included in Retail Margin Revenues.

Retail Revenues were lower in the second quarter of 2016 when compared with the same period in 2015, primarily due to a decrease in the PPFAC rate partially offset by higher Retail Margin Revenues. Retail Margin Revenues were higher primarily due to an increase in LFCR revenues.

27

Retail Revenues were $460 million in the second quarter of 2016 compared with $466 million in the second quarter of 2015. Retail Margin Revenues (Non-GAAP) were $292 million in the second quarter of 2016 compared with $288 million in the second quarter of 2015. The table below provides a summary of retail kWh sales, a reconciliation of Retail Margin Revenues to Retail Revenues, and weather data for the first six months of 2016 and 2015:

	Six Months Ended June 30,				Increase (Decrease)
	2016		2015		Amount			Percent
Retail Sales by Customer Class (kWh in millions)
Residential	1,647		1,604		43			2.7	%
Commercial	1,006		998		8			0.8	%
Industrial	947		982		(35		)	(3.6	)%
Mining	498		553		(55		)	(9.9	)%
Public Authorities	16		17		(1		)	(5.9	)%
Total Retail Sales by Class	4,114		4,154		(40		)	(1.0	)%
Retail Revenues (in millions)
Residential	$	125	$	122	$	3		2.5	%
Commercial	86		85		1			1.2	%
Industrial	50		50		—			—	%
Mining	17		19		(2		)	(10.5	)%
Public Authorities	1		1		—			—	%
Retail Margin Revenues by Class	279		277		2			0.7	%
LFCR Revenues	9		5		4			80.0	%
DSM Performance Bonus	2		3		(1		)	(33.3	)%
Other Retail Margin Revenues	2		3		(1		)	(33.3	)%
Retail Margin Revenues (Non-GAAP) (1)	292		288		4			1.4	%
Fuel and Purchased Power Revenues	145		154		(9		)	(5.8	)%
DSM and RES Surcharge Revenues	23		24		(1		)	(4.2	)%
Total Retail Revenues (GAAP)	$	460	$	466	$	(6	)	(1.3	)%
Average Retail Margin Rate by Class (cents /kWh)(2)
Residential	7.59		7.61		(0.02		)	(0.3	)%
Commercial	8.55		8.52		0.03			0.4	%
Industrial	5.28		5.09		0.19			3.7	%
Mining	3.41		3.44		(0.03		)	(0.9	)%
Public Authorities	5.64		5.62		0.02			0.4	%
Average Retail Margin Rate by Class	6.78		6.67		0.11			1.6	%
Total Average Retail Margin Rate (3)	7.10		6.93		0.17			2.5	%
Average Fuel and Purchased Power Rate	3.52		3.71		(0.19		)	(5.1	)%
Average DSM and RES Rate	0.56		0.58		(0.02		)	(3.4	)%
Total Average Retail Rate	11.18		11.22		(0.04		)	(0.4	)%
Weather Data
Cooling Degree Days
Actual	469		483		(14		)	(2.9	)%
10-year Average	473		480		*			*
Heating Degree Days
Actual	629		452		177			39.2	%
10-year Average	773		784		*			*

* Not meaningful

⁽¹⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues,

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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, LFCR revenues, DSM performance bonus, and certain other retail margin revenues available to cover the non-fuel operating expenses of our core utility business.

⁽²⁾  Calculated on unrounded data and may not correspond exactly to data shown in table.

⁽³⁾  Total Average Retail Margin Rate includes revenue related to LFCR, DSM Performance Bonus, and Other Retail Margin Revenues included in Retail Margin Revenues.

Retail Revenues were lower in the first six months of 2016 when compared with the same period in 2015 primarily due to a decrease in the PPFAC rate offset by higher Retail Margin Revenues. Retail Margin Revenues were higher primarily due to an increase in residential sales resulting from favorable weather conditions and an increase in LFCR revenues.

Wholesale Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016			2015
Long-Term Wholesale Revenues	$	10	$	11	$	16		$	18
Short-Term Wholesale Revenues	16		29		30			57
Transmission Revenues	8		8		15			14
Transmission Refunds (1)	—		—		(13		)	—
Total Wholesale Revenues	$	34	$	48	$	48		$	89

⁽¹⁾  FERC ordered TEP to make refunds associated with various late-filed TSAs for the time period during which rates were charged without FERC authorization. See Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the FERC order.

Wholesale Revenues decreased by $14 million, or 29.2%, in the second quarter of 2016 compared with the same period in 2015 primarily due to decreased volumes of short-term wholesale sales resulting from unfavorable market conditions.

Wholesale Revenues decreased by $41 million, or 46.1%, in the first six months of 2016 compared with the same period in 2015 primarily due to FERC ordered refunds associated with TSAs and decreased volumes of short-term wholesale sales resulting from unfavorable market conditions.

The majority of revenues from short-term wholesale sales is related to ACC jurisdictional assets and are returned to retail customers by crediting them against the fuel and purchased power costs eligible for recovery in the PPFAC.

Other Revenues

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Springerville Units 3 and 4 Revenue (1)	$	20	$	22	$	38	$	45
Other Revenue	7		6		14		14
Total Other Revenues	$	27	$	28	$	52	$	59

⁽¹⁾  Represents revenues and reimbursements from Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, to TEP related to the operation of these plants.

Total Other Revenues include reimbursements related to Springerville Units 3 and 4; 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.

There were no significant changes in Other Revenue noted in the second quarter of 2016 when compared with the same periods in 2015.

Springerville Units 3 and 4 Revenue decreased in the first six months of 2016 when compared with the same period in 2015 primarily due to a decrease in reimbursements of O&M expenses resulting from lower generating output in 2016 and planned

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generation outages in 2015. There were no significant changes in Other Revenue noted in the first six months of 2016 when compared with the same periods in 2015.

Operating Expenses

Generating Output and Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources are detailed in the following tables:

	Generation and Purchased Power (kWh)		Fuel and Purchased Power Expense
	Three Months Ended June 30,
(in millions)	2016	2015	2016		2015
Coal-Fired Generation	1,965	2,186	$	44	$	57
Gas-Fired Generation	817	543	23		19
Utility Owned Renewable Generation	19	20	—		—
Fuel Expense for Springerville Units 3 and 4(1)	—	—	1		1
Total Generation	2,801	2,749	68		77
Total Purchased Power	577	1,007	24		37
Transmission and Other PPFAC Recoverable Costs	—	—	5		7
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—	—	8		7
Total Generation and Purchased Power	3,378	3,756	$	105	$	128
Less Line Losses and Company Use	202	184
Total Energy Sold	3,176	3,572

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

Total Fuel and Purchased Power Expense decreased by $23 million, or 18.0%, in the second quarter of 2016 compared with the same period in 2015 primarily due to the decrease in purchased power volumes and lower fuel costs per kWh from all sources (see table below). The decrease in purchased power volumes was primarily due to the decrease in both retail and wholesale sales and the increase in Gas-Fired Generation.

	Generation and Purchased Power (kWh)		Fuel and Purchased Power Expense
	Six Months Ended June 30,
(in millions)	2016	2015	2016		2015
Coal-Fired Generation	3,589	4,124	$	87	$	111
Gas-Fired Generation	1,651	990	41		34
Utility Owned Renewable Generation	34	36	—		—
Reimbursed Fuel Expense for Springerville Units 3 and 4 (1)	—	—	3		3
Total Generation	5,274	5,150	131		148
Total Purchased Power	943	1,796	42		67
Transmission and Other PPFAC Recoverable Costs	—	—	10		11
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—	—	14		11
Total Generation and Purchased Power	6,217	6,946	$	197	$	237
Less Line Losses and Company Use	352	319
Total Energy Sold	5,865	6,627

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

Fuel and Purchased Power Expense decreased by $40 million, or 16.9%, in the first six months of 2016 compared with the same period in 2015 primarily due to the decrease in purchased power volumes and lower fuel costs per kWh from all sources (see table below). The decrease in purchased power volumes was primarily due to the decrease in both retail and wholesale sales and the increase in Gas-Fired Generation. These decreases were partially offset by an increase of PPFAC recovery treatment related to over collection of PPFAC costs.

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

	Three Months Ended June 30,		Six Months Ended June 30,
(cents per kWh)	2016	2015	2016	2015
Coal	2.26	2.58	2.41	2.69
Gas	2.80	3.60	2.52	3.40
Purchased Power - Non-Renewable	2.43	2.85	2.35	2.76
Purchased Power - Renewable	6.58	9.50	7.09	11.40
All Sources	3.31	3.38	3.37	3.42

Operations and Maintenance Expense

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Reimbursed Expenses - Springerville Units 3 and 4 (1)	$	14	$	16	$	25	$	32
Reimbursed Expenses - Customer Funded Renewable Energy and DSM Programs (2)	7		6		12		10
Other Operations and Maintenance Expense (3)	66		64		135		126
Total Operations and Maintenance Expense	$	87	$	86	$	172	$	168

⁽¹⁾  Expenses related to Springerville Units 3 and 4 are reimbursed with corresponding amounts recorded in other revenue.

⁽²⁾  These expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

⁽³⁾  The Third-Party Owners' share of expenses related to Springerville Unit 1 is included in Other Operating and Maintenance Expense.

Total O&M increased by $1 million, or 1.2%, in the second quarter of 2016 compared with the same period in 2015 due to higher operations and maintenance expense primarily from increases in maintenance expense due to planned generation outages.

Total O&M expense increased by $4 million, or 2.4%, in the first six months of 2016 compared with the same period in 2015 due to higher operations and maintenance expense primarily from increases in maintenance expense due to planned generation outages, outside services, and employee wages and benefits. The increase was partially offset by a decrease in Springerville Units 3 and 4 expenses related to economic shutdowns in 2016 and planned generation outages in 2015, which are reimbursed by third-party owners.

FACTORS AFFECTING RESULTS OF OPERATIONS

Regulatory Matters

TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2015 Annual Report on Form 10-K and new regulatory matters occurring in 2016.

2015 Rate Case

In November 2015, TEP filed a general rate case with the ACC to: (i) update and improve its rate design and tariffs to provide more accurate price signals and a more equitable allocation of its fixed costs to its customers; (ii) provide TEP with an opportunity to recover its full cost of service, including an appropriate return on its rate base investments; and (iii) enable TEP to continue to provide safe and reliable service. The rate application is based on a test year ended June 30, 2015. Hearings before an administrative law judge are scheduled to begin in August 2016. The filing requests that new rates be implemented by January 1, 2017.

The key provisions of the rate case include:

• a Base Rate increase of $110 million, or 12%, compared with adjusted test year revenues;

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• a 7.34% return on original cost rate base of $2.1 billion, which includes approximately $73 million of post-test year adjustments for utility plant that is expected to be in service by December 31, 2016;

• a capital structure for rate making purposes of approximately 50% common equity and 50% long-term debt;

• a cost of equity of 10.35% and an average cost of debt of 4.32%;

• a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement;

• a request for authority to begin using the Third-Party Owners' portion of Springerville Unit 1 that is available to TEP for dispatch to serve retail customer needs and to recover the related operating costs through the PPFAC; and

• rate design changes that would reduce the reliance on volumetric sales to recover fixed costs, and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service.

Following the review of intervener direct testimony, TEP filed rebuttal testimony on July 25, 2016. In rebuttal testimony, TEP revised its rate request to reflect a $101 million increase in Base Rates, proposed a 7.16% return on original cost rate base, proposed a cost of equity of 10.00%, and recovery of operating costs on the Third-Party Owners’ portion of SGS Unit 1 through Base Rates instead of through the PPFAC.

TEP cannot predict the outcome of this proceeding or whether its rate request will be adopted by the ACC in whole or in part.

Generating Resources

At June 30, 2016, approximately 49% of TEP's generating capacity was fueled by coal. 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 strategies and evaluating additional steps to reduce its reliance on coal generation.

In 2015, the on-site coal inventory at Sundt Unit 4 was depleted and the plant began operating on natural gas as a primary fuel source. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source as a better-than-BART alternative at Sundt Unit 4 by no later than December 2017.

TEP's ability to further reduce its coal-fired generating capacity will depend on several factors, including, but not limited to:

• the impact of the Clean Power Plan on current coal-fired generating facilities;

• whether TEP completes the purchase of the Third-Party Owners' undivided interest in Springerville Unit 1; and

• whether TEP chooses to exercise its option to exit San Juan Unit 1 in July 2022 upon the expiration of the current coal supply agreement.

See Liquidity and Capital Resources, Environmental Matters for additional information regarding the impact of environmental matters on plant operations.

Springerville Unit 1

TEP leased Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities 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 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 and LDVF1 (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). 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. Owner Trustees and Co-Trustees are obligated to compensate TEP for their pro rata share of expenses for the unit.

In April 2015, TEP filed a demand for arbitration seeking an award of the Owner Trustees and Co-Trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In October 2015, the arbitration panel granted TEP’s

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motion for interim relief, ordering the Owner Trustees and Co-Trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the Third-Party Owners’ motion for interim relief which had requested that TEP be enjoined from dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling, when economical, the Third-Party Owners’ entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015. As of June 30, 2016, TEP has billed the Third-Party Owners approximately $35 million for their pro-rata share of Springerville Unit 1 expenses and $7 million for their pro-rata share of capital expenditures, none of which had been paid as of July 28, 2016.

On February 29, 2016, TEP entered into an Agreement with the Third-Party Owners for settlement and release of asserted claims. The Agreement provides that: (i) TEP will purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million; and (ii) the Third-Party Owners will pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners. Upon completion of the purchase, all outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners will be dismissed with prejudice.

See Note 5 of the Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for a description of legal proceedings relating to the Third-Party Owners.

Potential Plant Retirements

In March 2016, as required by the ACC, TEP filed its preliminary 2016 Integrated Resource Plan (IRP), with the final 2017 IRP to be filed by April 2017. TEP's IRP includes plans to reduce its overall coal capacity by 170 MW (7% of TEP's existing coal fleet) by 2018 and options for further reductions through 2031. TEP's existing generation fleet faces a number of uncertainties related to plant participation and final outcomes of state plans for implementing the Clean Power Plan (CPP). Given this uncertainty, TEP may consider options that include changes in plant ownership shares, unit shutdowns, or sale of generation assets to third parties. TEP plans to seek regulatory recovery for amounts that would not otherwise be recovered if and when any assets are retired.

See Liquidity and Capital Resources, Environmental Matters for additional information regarding the impact of environmental matters on plant operations.

Springerville Coal Handling Facilities

In April 2015, upon the expiration of the lease term, TEP purchased an undivided ownership interest in the Springerville Coal Handling Facilities. With the completion of this purchase, Tri-State, the lessee of Springerville Unit 3, was obligated to either: (i) buy a 17.05% undivided interest in the facilities for approximately $24 million; or (ii) continue to make payments to TEP for the use of the facilities. In March 2016, Tri-State notified TEP that it was exercising its option to purchase the undivided interest in the facilities. The Tri-State purchase is expected to close by the end of 2016. TEP currently collects rent of $4 million per year related to Tri-State's portion of the Springerville Coal Handling Facilities. At June 30, 2016, Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities is classified as Assets Held for Sale in the Condensed Consolidated Balance Sheets.

Sales to Mining Customers

TEP's largest mining customer has taken steps to reduce operational expenses by curtailing production in 2016 due to a decline in commodity prices. As a result, retail sales from mining customers have declined by 9.9% for the first six months of 2016 when compared with the same period in 2015. While TEP cannot predict how long commodity prices will remain low or the total impact the prices will have on mining production in the future, any future curtailment of mining production could negatively impact retail sales for mining customers. For the first six months of 2016, mining customers accounted for 12.1% of TEP's retail sales and 7.1% of Retail Revenues.

Interest Rates

See Part II, Item 7A in our 2015 Annual Report on Form 10-K and Part II, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Cash flows may vary during the year with cash flows from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, we will use, as needed, our revolving credit facility to assist in funding business activities. We believe that we have sufficient liquidity under our revolving credit facility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which TEP has access to external financing depends on a variety of factors, including its credit ratings and conditions in the overall capital markets.

Available Liquidity

(in millions)	June 30, 2016
Cash and Cash Equivalents	$	39
Amount Available under Revolving Credit Facility (1)	250
Total Liquidity	$	289

⁽¹⁾  TEP's revolving credit facility, which matures in 2020, provides for a $250 million revolving credit commitment with a LOC sublimit of $50 million.

Future Liquidity Requirements

We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to, dividend payments, debt maturities, and obligations included in the Contractual Obligations and forecasted Capital Expenditures tables reported in our 2015 Annual Report on Form 10-K and the material changes summarized below in the respective sections.

Summary of Cash Flows

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

	Six Months Ended June 30,						Increase (Decrease)
(in millions)	2016			2015			Percent
Operating Activities	$	157		$	129		21.7	%
Investing Activities	(156		)	(349		)	(55.3	)%
Financing Activities	(18		)	250			(107.2	)%
Net Increase (Decrease) in Cash	(17		)	30			(156.7	)%
Cash and Cash Equivalents, Beginning of Period	56			74			(24.3	)%
Cash and Cash Equivalents, End of Period	$	39		$	104		(62.5	)%

Operating Activities

In the first six months of 2016, net cash flows from operating activities increased by $28 million compared with the same period in 2015 primarily due to:

• $33 million decrease in cash paid for fuel and purchased power costs;

• $4 million decrease in cash paid for pension and retiree funding; and

• $3 million decrease in cash paid for interest on debt and capital leases, net of amounts capitalized.

The increase was partially offset by $11 million increase in cash paid for incentive compensation in the first six months of 2016 compared with the same period last year. As a result of the Fortis acquisition in 2014, payments under the annual incentive compensation plan were accelerated to the third quarter 2014 from the first quarter 2015.

Investing Activities

In the first six months of 2016, net cash flows used for investing activities decreased by $193 million compared with the same period in 2015 primarily due to:

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• $46 million purchase, in January 2015, of an additional 24.8% undivided ownership interest in Springerville Unit 1 increasing its total ownership interest to 49.5%;

• $120 million purchase, in April 2015, of an additional 86.7% undivided ownership interest in the Springerville Coal Handling Facilities increasing its total ownership interest to 100%; and

• $60 milliondecrease in cash paid in 2016 for capital expenditures primarily due to cost for the construction of a new 500kV transmission line in 2015.

The decrease in net cash flows used for investing activities was partially offset by the sale, in May 2015, of a 17.05% undivided ownership interest in Springerville Coal Handling Facilities for approximately $24 million to SRP.

Financing Activities

In the first six months of 2016, net cash flows from financing activities decreased by $268 million compared with the same period in 2015 primarily due to:

• $299 million decrease in cash proceeds in 2016 due to the issuance of long-term debt, in February 2015; and

• $180 million decrease in cash proceeds in 2016 due to UNS Energy equity contribution, in June 2015.

The decrease in net cash flows from financing activities was partially offset by:

• $130 million decrease in cash paid in 2016 due to the purchase of tax-exempt long-term debt in January 2015; and

• $85 million decrease in cash paid in 2016, net of proceeds borrowed, under TEP's revolving credit facilities.

External Sources of Liquidity

Short-Term Investments

TEP’s short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. At June 30, 2016, TEP's short-term investments included highly-rated and liquid money market funds.

Access to Revolving Credit Facility

We have access to working capital through a revolving credit agreement with lenders. TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. No amounts were drawn under the 2015 Credit Agreement at June 30, 2016.

For details on TEP's credit facility see Note 4 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Debt Financing

We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.

In January 2016, the ACC issued an order granting TEP financing authority. The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority.

We have no financings to raise additional capital planned for 2016. TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, TEP may refinance other debt issuances or make additional debt repurchases in the future.

Credit Ratings

Our credit ratings affect our access to capital markets and supplemental bank financing. At June 30, 2016, TEP’s credit ratings for senior unsecured debt were A3 from Moody’s and BBB+ from Standard & Poor’s.

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TEP's credit ratings are dependent on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.

Debt Covenants

Certain of TEP's 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. Also, under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. At June 30, 2016, TEP was in compliance with these covenants.

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 a 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. At June 30, 2016, TEP had posted no LOCs for credit enhancement with wholesale counterparties.

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.

Contribution from Parent

TEP received no equity contributions in the first six months of 2016. In June 2015, UNS Energy made an equity contribution of $180 million to TEP. The contribution was used to repay revolving credit loans, redeem bonds, and provide additional liquidity to TEP.

Dividends

TEP did not declare or pay dividends in the first six months of 2016 or 2015. On July 27, 2016, TEP declared and paid $20 million in dividends to UNS Energy.

The ACC's approval of the acquisition of UNS Energy by Fortis, in August 2014, contained a condition restricting TEP's dividend payments to UNS Energy to no more than 60% of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reached 50% as accounted for in accordance with GAAP. At June 30, 2016, TEP’s equity ratio reached 50.1% of total capital.

Capital Expenditures

TEP's routine capital expenditures include funds used for system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. There have been no changes in TEP's forecasted capital expenditures from those reported in our 2015 Annual Report on Form 10-K, other than normal recurring subsequent review adjustments and the $85 million purchase of the Third-Party Owners' 50.5% undivided ownership interest in Springerville Unit 1 in 2016.

Contractual Obligations

In 2016, there have been no changes in TEP's contractual obligations or other commercial commitments from those reported in our 2015 Annual Report on Form 10-K, other than the following:

• $85 million purchase of the Third-Party Owners' 50.5% undivided ownership interest in Springerville Unit 1 in 2016; and

• long-term commitments entered into by TEP through June 30, 2016, as described in Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Income Tax Position

Prior year tax legislation and the Consolidated Appropriations Act of 2016 include provisions that make qualified property placed in service between 2010 and 2019 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 in the first six months of 2016 and does not expect to make any payments until 2020.

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Off-Balance Sheet Arrangements

Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2015 Annual Report on Form 10-K, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.

Environmental Matters

The EPA regulates the amount of sulfur dioxide (SO₂), nitrogen oxide (NO_x), carbon dioxide (CO₂), particulate matter, mercury and other by-products produced 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. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.

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. TEP, as operator of Springerville and Sundt, and the operators of Navajo and Four Corners received extensions until April 2016 to comply with the MATS rules.

In June 2015, the D.C. Circuit Court of Appeals remanded the MATS rules to the EPA for further consideration. Despite the June 2015 ruling, TEP proceeded with its planned MATS compliance activity at each generating station.

In March 2016, the installation of mercury control systems was completed at Navajo. TEP’s share of the installation costs were approximately $1 million. In addition, TEP completed the installation of mercury control systems on Units 1 and 2 at Springerville in March 2016. TEP’s share of the installation costs were approximately $3 million. At this time, all generating stations TEP operates or is a participant in are in compliance with the MATS rules.

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls 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 NO_x, often resulting in a requirement to install Selective Catalytic Reduction (SCR). Complying with the BART rule, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of Navajo and Four Corners or for individual owners to continue to participate in these power plants. The BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s, after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reductions are not likely to impact Springerville operations until after 2018. In May 2016, the EPA published a proposed rule, entitled "Protection of Visibility: Amendments to Requirements for State Plans." Among other things, the rule proposes to change the date for submittal of the next regional haze implementation plan from 2018 to 2021, extending the time for potential impact to Springerville to 2021. TEP cannot predict the ultimate outcome of these matters.

TEP's estimated NO_x emissions control costs to comply with the rules includes the following:

(in millions)	Navajo		Four Corners
Capital Expenditures	$	47	$	44
Annual O&M Expenses	2		2
Compliance Year	2030		2018

Navajo

In August 2014, the EPA published a final Federal Implementation Plan (FIP) which provides that 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

37

generation will cease by December 2044. The final BART rule includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA of how it will comply with the FIP.

Four Corners

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 agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

San Juan

In October 2014, the EPA published a final rule approving a revised SIP covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of SNCR on Units 1 and 4. TEP owns 50% of Units 1 and 2 at San Juan. PNM, the operator of San Juan, completed the installation of SNCR in February 2016. TEP's share of installation costs were $12 million. PNM obtained New Mexico Public Regulation Commission approval to shut down Units 2 and 3 at San Juan.

At June 30, 2016, the NBV of TEP's share in San Juan Unit 2 was $101 million. Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered NBV in its 2015 Rate Case.

Sundt

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 was required to notify the EPA of its decision by March 2017. In March 2016, TEP notified the EPA of its decision to comply with the better-than-BART alternative emission limits. See Note 2 of the Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information.

Greenhouse Gas Regulation

In August 2015, the EPA issued the CPP limiting CO₂ emissions from existing and new fossil fueled power plants. The CPP establishes state-level CO₂ emission rates and mass-based goals that apply to fossil fuel-fired generation. The plan targets CO₂ emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022. States are required to develop and submit a final compliance plan, or an initial plan with an extension request, to the EPA by September 2016. States that receive an extension must submit a final completed plan to the EPA by September 2018. TEP will continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop the state compliance plans. TEP is unable to determine how the final CPP rule will impact its facilities until state plans are developed and approved by the EPA. TEP cannot predict the ultimate outcome of these matters.

The EPA incorporated the compliance obligations for existing power plants located in Indian Country, like the Navajo Nation, in the existing sources rule and a newly proposed Federal Plan using a compliance method similar to that of the states. The proposed Federal Plan would be implemented for any Indian nation and/or state that does not submit a plan or that does not have an EPA or approved state plan. TEP will work with the participants at Four Corners and Navajo to determine how this revision may impact compliance and operations at both facilities. TEP has submitted comments on the proposed Federal Plan impacting our facilities, including Four Corners and Navajo, stating, among other things, that the EPA should not regulate the greenhouse gases on the Navajo Nation because it is not appropriate or necessary. The reduction of greenhouse gases achieved due to the shutdowns resulting from Regional Haze compliance will be equivalent to those required under the CPP rule. TEP cannot predict the ultimate outcome of these matters.

TEP's compliance requirements under the CPP are subject to the outcomes of potential proceedings and litigation challenging the rule. In February 2016, the U.S. Supreme Court granted a stay effectively ordering the EPA to stop CPP implementation efforts until legal challenges to the regulation have been resolved. The ruling introduces uncertainty as to whether and when the states and utilities will have to comply with the CPP rule. TEP will continue to work with the Arizona Department of Environmental Quality to determine what, if any, actions need to be taken in light of the ruling. TEP anticipates that the ruling will likely delay the requirement to submit a plan or request an extension under the CPP by September 2016.

Coal Combustion Residuals Regulation

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 for disposal in landfills and/or surface impoundments while allowing for the continued recycling of coal ash. TEP does not own or operate any impoundments. Under the rule, the

38

Springerville ash landfill is classified as an existing landfill and is not subject to the lateral expansion requirements. However, TEP will incur additional costs for site preparation and monitoring at Springerville to be fully compliant with the rule. TEP’s share of the cost at Springerville is estimated to be $2 million, the majority of which is expected to be capital expenditures. TEP currently estimates its share of the costs to be $5 million at Four Corners, $3 million at Navajo, and less than $1 million at San Juan, the majority of which are expected to be capital expenditures.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, net revenues and expenses, and disclosure of contingent liabilities. Our management believes that there have been no significant changes during the six months ended June 30, 2016, to the items that we disclosed as our critical accounting policies and estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2015 Annual Report on Form 10-K.

ACCOUNTING PRONOUNCEMENTS

For a discussion of new accounting pronouncements affecting TEP, see Note 9 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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 can 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 2015 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13(a) – 15(e) or Rule 15(d) – 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 United States 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 persons 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 June 30, 2016.

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 six months ended June 30, 2016, 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

For a description of certain legal proceedings affecting TEP, refer to Note 5 of the Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

As previously reported, TEP and the Third-Party Owners are parties to litigation and arbitration proceedings relating to Springerville Unit 1.

On February 29, 2016, TEP entered into an agreement with the Third-Party Owners for settlement and release of asserted claims. The Agreement provides that TEP will purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million and the Third-Party Owners will pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners. Upon completion of the purchase, all outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners will be dismissed with prejudice.

The purchase of Third-Party Owners' undivided interest in Springerville Unit 1 is subject to, among other things, FERC approval and satisfaction of other customary closing conditions. TEP expects the purchase to close in the third quarter of 2016. However, there is no assurance that the settlement will be finalized or that the litigation will not continue. Therefore, at this time 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 claims, TEP cannot determine estimates of the range of loss, if any, at this time. Should the litigation matters continue, TEP intends to continue vigorously defending itself against the claims asserted by the Third-Party Owners and to vigorously pursue the claims it has asserted against the Owner Trustees and Co-Trustees.

ITEM 1A. RISK FACTORS

The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2015 Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2015 Form 10-K.

ITEM 5. OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended June 30, 2016	Twelve Months Ended June 30, 2016
Ratio of Earnings to Fixed Charges	2.58	3.65

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.

ITEM 6. EXHIBITS

See Exhibit Index.

40

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:	July 29, 2016	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer
		(On behalf of the registrant and as Principal Financial Officer)

41

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.

42

EX-12

Exhibit 12

TUCSON ELECTRIC POWER COMPANY

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended		Twelve Months Ended
	June 30,		June 30,		December 31,
(in thousands)	2016		2016		2015		2014		2013		2012		2011
Net Income	$	39,834	$	120,373	$	127,794	$	102,338	$	101,342	$	65,470	$	85,334
Add:
Income Tax Expense	14,429		61,382		71,719		57,911		47,986		39,109		52,000
Interest Expense, Net (1)	32,087		63,846		63,555		68,555		80,793		91,295		93,786
Estimated Interest Portion of Rental Expense (2)	837		1,496		1,711		1,691		842		611		795
Total Earnings before Taxes and Fixed Charges	$	87,187	$	247,097	$	264,779	$	230,495	$	230,963	$	196,485	$	231,915
Fixed Charges:
Interest Expense (before deducting capitalized interest) (3)	$	32,948	$	66,243	$	69,179	$	88,340	$	85,591	$	93,077	$	95,859
Estimated Interest Portion of Rental Expense	837		1,496		1,711		1,691		842		611		795
Total Fixed Charges	$	33,785	$	67,739	$	70,890	$	90,031	$	86,433	$	93,688	$	96,654
Ratio of Earnings to Fixed Charges	2.58		3.65		3.74		2.56		2.67		2.10		2.40

⁽¹⁾  Interest on uncertain tax positions is included in Interest Expense.

⁽²⁾  The Estimated Interest Portion of Rental Expense is calculated by using our estimated incremental borrowing rate times the present value of projected operating lease payments.

⁽³⁾  Excludes recognition of Allowance for Borrowed Funds Used During Construction.

EX-31.A

Exhibit 31(a)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, David G. Hutchens, certify that: 

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2016, of Tucson Electric Power Company; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 29, 2016	/s/ David G. Hutchens
		David G. Hutchens
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Kevin P. Larson, certify that: 

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2016, of Tucson Electric Power Company; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): 

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and     

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 29, 2016	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32

Exhibit 32

STATEMENTS OF CORPORATE OFFICERS

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Each of the undersigned, David G. Hutchens, President and Chief Executive Officer of Tucson Electric Power Company (the “Company”), and Kevin P. Larson, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	July 29, 2016	/s/ David G. Hutchens
		David G. Hutchens
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	July 29, 2016	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 28, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	0000100122
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		32,139,434

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating Revenues
Retail	$ 256,450	$ 264,297	$ 460,403	$ 465,920
Wholesale	34,084	47,674	48,497	89,136
Other	26,950	28,204	52,063	58,512
Total Operating Revenues	317,484	340,175	560,963	613,568
Operating Expenses
Fuel	68,236	77,067	130,914	147,636
Purchased Power	24,023	36,885	41,763	67,407
Transmission and Other PPFAC Recoverable Costs	5,312	6,873	10,490	11,580
Increase (Decrease) to Reflect PPFAC Recovery Treatment	7,470	7,532	14,265	10,781
Total Fuel and Purchased Power	105,041	128,357	197,432	237,404
Operations and Maintenance	86,580	85,655	171,579	168,300
Depreciation	35,913	34,219	71,545	68,952
Amortization	5,545	4,619	11,021	10,181
Taxes Other Than Income Taxes	12,700	12,935	25,730	26,146
Total Operating Expenses	245,779	265,785	477,307	510,983
Operating Income	71,705	74,390	83,656	102,585
Other Income (Deductions)
Interest Income	29	22	67	51
Other Income	1,260	1,436	2,653	2,058
Other Expense	(463)	(656)	(886)	(1,118)
Appreciation (Depreciation) in Value of Investments	660	(539)	860	241
Total Other Income (Deductions)	1,486	263	2,694	1,232
Interest Expense
Long-Term Debt	15,486	15,706	30,977	30,116
Capital Leases	855	1,007	1,713	2,012
Other Interest Expense	135	430	258	864
Interest Capitalized	(397)	(741)	(861)	(1,196)
Total Interest Expense	16,079	16,402	32,087	31,796
Income Before Income Taxes	57,112	58,251	54,263	72,021
Income Tax Expense	16,576	20,425	14,429	24,766
Net Income	$ 40,536	$ 37,826	$ 39,834	$ 47,255

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income	$ 40,536	$ 37,826	$ 39,834	$ 47,255
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges:	129	441	138	455
Supplemental Executive Retirement Plan Adjustments:	57	61	113	121
Total Other Comprehensive Income (Loss), Net of Tax	186	502	251	576
Total Comprehensive Income	$ 40,722	$ 38,328	$ 40,085	$ 47,831

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Tax (Expense) Benefit related to Change in Fair Value of Cash Flow Hedges	$ 81	$ 282	$ 87	$ 294
Tax (Expense) Benefit related to Supplemental Executive Retirement Plan Adjustment	$ 35	$ 38	$ 70	$ 75

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Statement of Cash Flows [Abstract]
Net Income	$ 39,834	$ 47,255
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	71,545	68,952
Amortization Expense	11,021	10,181
Amortization of Debt Issuance Costs	1,451	1,499
Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue	12,041	11,170
Use of Renewable Energy Credits for Compliance	8,403	12,014
Deferred Income Taxes	14,428	23,835
Pension and Retiree Expense	7,669	9,294
Pension and Retiree Funding	(5,694)	(9,886)
Share-Based Compensation Expense	1,244	672
Allowance for Equity Funds Used During Construction	(2,203)	(1,419)
FERC Refund Order	10,086	0
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(33,748)	(44,886)
Materials, Supplies, and Fuel Inventory	4,151	(3,326)
Regulatory Assets	(8,579)	6,183
Accounts Payable and Accrued Charges	11,985	9,590
Regulatory Liabilities	13,588	(7,727)
Other, Net	(694)	(4,564)
Net Cash Flows—Operating Activities	156,528	128,837
Cash Flows from Investing Activities
Capital Expenditures	(135,344)	(194,915)
Purchase of Springerville Coal Handling Facilities Lease Assets	0	(120,312)
Purchase of Springerville Unit 1 Lease Assets	0	(45,753)
Proceeds from Sale of Springerville Coal Handling Facilities	0	23,656
Purchase of Intangibles - Renewable Energy Credits	(19,570)	(15,002)
Contributions in Aid of Construction	(722)	3,297
Net Cash Flows—Investing Activities	(155,636)	(349,029)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	0	148,000
Repayments of Borrowings Under Revolving Credit Facilities	0	(233,000)
Proceeds from Borrowings Under Term Loan	0	130,000
Repayments of Borrowings Under Term Loan	0	(130,000)
Proceeds from Issuance of Long-Term Debt	0	299,019
Repayments of Long-Term Debt	0	(130,000)
Payments of Capital Lease Obligations	(13,703)	(12,440)
Payment of Debt Issue/Retirement Costs	0	(2,920)
Contribution from Parent	0	180,000
Other, Net	(4,028)	898
Net Cash Flows—Financing Activities	(17,731)	249,557
Net Increase (Decrease) in Cash and Cash Equivalents	(16,839)	29,365
Cash and Cash Equivalents, Beginning of Period	55,684	74,170
Cash and Cash Equivalents, End of Period	$ 38,845	$ 103,535

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Utility Plant
Plant in Service	$ 5,629,448	$ 5,618,435
Utility Plant Under Capital Leases	131,705	131,705
Construction Work in Progress	119,717	102,028
Total Utility Plant	5,880,870	5,852,168
Accumulated Depreciation and Amortization	(2,195,490)	(2,194,301)
Accumulated Amortization of Capital Lease Assets	(102,075)	(99,638)
Total Utility Plant, Net	3,583,305	3,558,229
Investments and Other Property	40,369	39,569
Current Assets
Cash and Cash Equivalents	38,845	55,684
Accounts Receivable, Net	158,036	136,682
Fuel Inventory	32,184	34,600
Materials and Supplies	91,737	94,003
Regulatory Assets	55,787	51,841
Derivative Instruments	5,019	1,808
Assets Held for Sale, Net	21,550	21,550
Other	17,642	25,904
Total Current Assets	420,800	422,072
Regulatory and Other Assets
Regulatory Assets	213,403	212,312
Derivative Instruments	986	430
Other	34,824	16,866
Total Regulatory and Other Assets	249,213	229,608
Total Assets	4,293,687	4,249,478
Capitalization
Common Stock (No Par Value, 75,000 Shares Authorized, 32,139 Shares Outstanding at June 30, 2016 and December 31, 2015)	1,296,539	1,296,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	229,151	189,317
Accumulated Other Comprehensive Loss	(4,313)	(4,564)
Total Common Stock Equity	1,515,020	1,474,935
Preferred Stock (No Par Value, 1,000 Shares Authorized, None Outstanding at June 30, 2016 and December 31, 2015)	0	0
Capital Lease Obligations	39,658	55,324
Long-Term Debt, Net	1,452,396	1,451,720
Total Capitalization	3,007,074	2,981,979
Current Liabilities
Current Obligations Under Capital Leases	15,636	14,114
Accounts Payable	80,292	86,274
Accrued Taxes Other than Income Taxes	39,960	37,577
Accrued Employee Expenses	20,961	27,718
Accrued Interest	14,440	14,246
Regulatory Liabilities	68,474	53,077
Customer Deposits	21,008	20,349
Derivative Instruments	5,513	12,174
Other	22,668	7,533
Total Current Liabilities	288,952	273,062
Regulatory and Other Liabilities
Deferred Income Taxes, Net	479,053	468,024
Regulatory Liabilities	304,512	307,286
Pension and Other Postretirement Benefits	119,126	120,336
Derivative Instruments	2,354	4,067
Other	92,616	94,724
Total Regulatory and Other Liabilities	997,661	994,437
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 4,293,687	$ 4,249,478

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (Unaudited) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common Stock, No Par Value ($ per share)	$ 0	$ 0
Common Stock, Shares Authorized	75,000,000	75,000,000
Common Stock, Shares, Outstanding	32,139,000	32,139,000
Preferred Stock, No Par Value ($ per share)	$ 0	$ 0
Preferred Stock, Shares Authorized	1,000,000	1,000,000
Preferred Stock, Shares Outstanding	0	0

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited) - USD ($) $ in Thousands	Total	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
Balances at Dec. 31, 2014	$ 1,215,779	$ 1,116,539	$ (6,357)	$ 111,523	$ (5,926)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	47,255			47,255
Other Comprehensive Income (Loss), Net of Tax	576				576
Contribution from Parent	180,000	180,000
Balances at Jun. 30, 2015	1,443,610	1,296,539	(6,357)	158,778	(5,350)
Balances at Dec. 31, 2015	1,474,935	1,296,539	(6,357)	189,317	(4,564)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	39,834			39,834
Other Comprehensive Income (Loss), Net of Tax	251				251
Balances at Jun. 30, 2016	$ 1,515,020	$ 1,296,539	$ (6,357)	$ 229,151	$ (4,313)

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 419,000 retail 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).

References in these notes to "we" and "our" are to TEP.

BASIS OF PRESENTATION

We prepared our condensed consolidated financial statements according to Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. 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 in 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 and should be read in conjunction with the consolidated financial statements and footnotes in our 2015 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 operating results are not indicative of annual operating results.

Certain amounts from prior periods have been reclassified to conform to the current period presentation.

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REGULATORY MATTERS

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

REGULATORY MATTERS

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.

2015 RATE CASE

In November 2015, TEP filed a general rate case with the ACC based on a test year ended June 30, 2015 (2015 Rate Case). Hearings before an administrative law judge are scheduled to begin in August 2016. The filing requests that new rates be implemented by January 1, 2017.

The key provisions of TEP's general rate case include:

• a Base Rate increase of $110 million, or 12%, compared with adjusted test year revenues;

• a 7.34% return on original cost rate base of $2.1 billion;

• a request to apply excess depreciation reserves against the unrecovered net book value (NBV) of the San Juan Generating Station (San Juan) Unit 2 and the coal handling facilities at the H. Wilson Sundt Generating Station (Sundt) due to early retirement;

• a request for authority to begin using the Third-Party Owners' portion of Springerville Generating Station (Springerville) Unit 1 that is available to TEP for dispatch to serve retail customers' needs and to recover the related operating costs through the Purchased Power and Fuel Adjustment Clause (PPFAC); and

• rate design changes that would reduce the reliance on volumetric sales to recover fixed costs and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service.

TEP cannot predict the outcome of this proceeding or whether its rate request will be adopted by the ACC in whole or in part.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.

The table below presents TEP's PPFAC rates approved by the ACC:

Period	Cents per kWh
May 2016 through March 2017 (1)	0.15
April 2015 through April 2016	0.68
October 2014 through March 2015 (2)	0.50

⁽¹⁾  In April 2016, the ACC approved the PPFAC rate adjustment effective May 2016.

⁽²⁾  The ACC approved a new rate effective October 2014.

Renewable Energy Standards

The ACC’s Renewable Energy Standard (RES) requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge until such costs are reflected in TEP’s Base Rates.

In May 2016, the ACC approved TEP's 2016 RES implementation plan that included a budget of $57 million, which will be partially offset by applying approximately $9 million of previously recovered carryover funds. TEP will recover the remaining $48 million through the RES surcharge. The budget will fund the following: (i) the above market cost of renewable energy purchases; (ii) previously awarded performance-based incentives for customer installed distributed generation; (iii) depreciation and a return on TEP's investments in company-owned solar projects; and (iv) various other program costs. The ACC deferred its decision on two proposals related to TEP's utility-owned rooftop solar and community solar projects. As a result, TEP is pursuing approval of these programs and related tariffs in the 2015 Rate Case.

The percentage of retail kilowatt-hour (kWh) sales attributable to the 2015 RES renewable energy requirement was 8.6%, which exceeded the overall 2015 requirement of 5.0%. TEP expects to meet the 2016 requirement of 6.0% of retail kWh sales. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain distributed generation renewable energy credits, which are used to demonstrate compliance with the distributed generation requirement, the company has requested, and the ACC has approved, a waiver of the 2016 residential distributed generation RES incremental requirement. In addition to the 2016 annual waiver, the ACC granted a waiver to TEP for the 2017 calendar year.

Energy Efficiency Standards

TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency Standards (EE Standards). The EE Standards provide for a DSM surcharge for regulated utilities to recover from retail customers the costs to implement DSM programs as well as an annual performance incentive. TEP records its annual DSM performance incentive in the first quarter of each year, with $2 million recorded in 2016 and $3 million in 2015 related to performance in each respective prior calendar year. This performance incentive is included in Retail Revenues on the Condensed Consolidated Statements of Income.

In February 2016, the ACC approved TEP’s 2016 energy efficiency implementation plan. Under the 2016 plan, TEP will recover approximately $14 million from retail customers and will offer customers new and existing DSM programs. Energy savings realized through the programs will count toward the EE Standards and the associated lost revenue will be partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and distributed generation targets. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to file an annual LFCR adjustment request with the ACC to recover the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of TEP's applicable retail revenues.

TEP recorded a regulatory asset and recognized LFCR revenues of $4 million and $9 million in the three and six months ended June 30, 2016, respectively. TEP recorded $3 million and $5 million in the three and six months ended June 30, 2015, respectively. LFCR revenues are included in Retail Revenues on the Condensed Consolidated Statements of Income.

Appellate Review of Rate Decisions

In a 2015 appellate challenge to two ACC rate decisions regarding a water company, the Arizona Court of Appeals considered the issue of how the ACC should determine a utility’s “fair value,” as specified in the Arizona Constitution, in connection with authorizing recovery of costs through rate adjustors outside of a rate case. The Court reversed the ACC’s method of finding fair value in that case and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. In February 2016, the Arizona Supreme Court granted the ACC’s request for review of this decision. In March 2016, the Supreme Court heard oral arguments on this matter. If the Supreme Court upholds the decision without modification, certain TEP rate adjustors may be negatively affected which could have a significant impact on TEP’s ability to recover certain costs between rate cases. TEP filed a brief in support of the ACC’s petition to the Supreme Court for review of the Court of Appeals’ decision, but cannot predict the outcome of this matter.

FERC MATTERS

In April 2016, the FERC issued an order (FERC Refund Order) relating to certain late-filed transmission service agreements (TSAs), which directed TEP to issue time value refunds to the relevant counterparties to these TSAs, in an amount up to $13 million. See Note 5 for additional information related to FERC compliance associated with transmission contracts.

REGULATORY ASSETS AND LIABILITIES

Regulatory assets are either being collected or expected to be collected through Retail Rates. With the exception of the Third-Party Owners' share of the Springerville Unit 1 Leasehold Improvements and Sundt Coal Handling Facilities, we do not earn a return on regulatory assets. Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs, TEP does not pay or accrue a return on regulatory liabilities.

The regulatory assets and liabilities recorded in the Condensed Consolidated Balance Sheets are summarized in the table below:

(in millions)	Remaining Recovery Period (years)	June 30, 2016		December 31, 2015
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	116	$	120
Final Mine Reclamation and Retiree Health Care Costs (1)	21	30		28
Property Tax Deferrals	1	22		21
Income Taxes Recoverable through Future Rates	Various	22		26
Lost Fixed Cost Recovery	1	21		16
Springerville Unit 1 Leasehold Improvements - Third-Party Owners (2)	7	19		21
Sundt Coal Handling Facilities (3)	Plant Life	17		—
Derivatives (Note 8)	3	3		12
Other Regulatory Assets	Various	19		20
Total Regulatory Assets		269		264
Less Current Portion	1	56		52
Total Non-Current Regulatory Assets		$	213	$	212

Regulatory Liabilities
Net Cost of Removal for Interim Retirements (4)	Various	$	263	$	264
Purchased Power and Fuel Adjustment Clause	1	34		18
Deferred Investment Tax Credits	Various	32		32
Renewable Energy Standard	Various	25		25
Other Regulatory Liabilities	Various	19		21
Total Regulatory Liabilities		373		360
Less Current Portion	1	68		53
Total Non-Current Regulatory Liabilities		$	305	$	307

⁽¹⁾  Final Mine Reclamation and Retiree Health Care Costs are recognized at future value. TEP will fully recover these costs through the PPFAC when paid. The majority of our final mine reclamation costs are expected to occur through 2037.

⁽²⁾  Springerville Unit 1 Leasehold Improvements represent investments TEP made, previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10-year amortization period.

⁽³⁾  In June 2014, the Environmental Protection Agency (EPA) issued a final rule that would require TEP to either: (i) install, by mid-2017, Selective Non-Catalytic Reduction (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-Best Available Retrofit Technology (BART) alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered NBV in its 2015 Rate Case.

⁽⁴⁾  Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

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RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

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

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	June 30, 2016		December 31, 2015
Receivables from Related Parties
UNS Electric	$	4	$	6
UNS Gas	1		1
Total Due from Related Parties	$	5	$	7
Payables to Related Parties
SES	$	2	$	2
UNS Energy	1		2
UNS Electric	—		2
Total Due to Related Parties	$	3	$	6

The following table presents the related party transactions included in the Condensed Consolidated Statements of Income:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Goods and Services Provided by TEP to Affiliates
Transmission Revenues - UNS Electric (1)	$	2	$	2	$	3	$	3
Wholesale Revenues - UNS Electric (1)	—		—		—		1
Control Area Services - UNS Electric (2)	1		—		1		1
Common Costs - UNS Energy Affiliates (3)	4		3		7		6
Goods and Services Provided by Affiliates to TEP
Wholesale Revenues - UNS Electric (1)	$	—	$	—	$	—	$	1
Supplemental Workforce - SES (4)	3		4		7		8
Corporate Services - UNS Energy (5)	2		1		4		2
Corporate Services - UNS Energy Affiliates (6)	2		—		2		—

⁽¹⁾  TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates, through the applicable Open Access Transmission Tariff.

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

⁽³⁾  Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

⁽⁴⁾  SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁵⁾  Costs for corporate services at UNS Energy include Fortis management fees, legal fees, and audit fees which 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 82% of UNS Energy's allocated costs. For the three and six months ended June 30, 2016, these costs included approximately $2 million and $4 million, respectively in Fortis management fees. For the three and six months ended June 30, 2015, Fortis management fees were $1 million and $2 million, respectively.

⁽⁶⁾  Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

DIVIDEND PAID

TEP did not declare or pay dividends in the first six months of 2016 or 2015. On July 27, 2016, TEP declared and paid $20 million in dividends to UNS Energy.

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

There have been no significant changes to our debt, credit facilities, or capital lease obligations from those reported in our 2015 Annual Report on Form 10-K, except as noted below.

CAPITAL LEASE OBLIGATIONS

Springerville Coal Handling Facilities

In April 2015, upon the expiration of the lease term, TEP purchased an undivided ownership interest in the coal handling facilities at Springerville used by all four Springerville units (Springerville Coal Handling Facilities). With the completion of this purchase, Tri-State Generation and Transmission Association, Inc. (Tri-State) was obligated to either: (i) buy a 17.05% undivided interest in the facilities for approximately $24 million; or (ii) continue to make payments to TEP for the use of the facilities. In March 2016, Tri-State notified TEP that it was exercising its option to purchase the undivided interest in the facilities. The Tri-State purchase is expected to close by the end of 2016. At June 30, 2016, Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities is classified as Assets Held for Sale on the Condensed Consolidated Balance Sheets.

COVENANT COMPLIANCE

At June 30, 2016, we were in compliance with the terms of our credit and long-term debt agreements.

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

COMMITMENTS

In addition to those reported in our 2015 Annual Report on Form 10-K, TEP entered into the following long-term commitments through June 30, 2016:

(in millions)	2016		2017		2018		2019		2020		Thereafter		Total
Fuel, Including Transportation	$	21	$	23	$	24	$	24	$	23	$	22	$	137
Transmission	2		4		4		4		4		3		21
Renewable Power Purchase Agreements	3		3		3		3		3		43		58
Total Purchase Commitments	$	26	$	30	$	31	$	31	$	30	$	68	$	216

TEP's transmission and fuel costs, including transportation, are recoverable from customers through the PPFAC mechanism. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.

Fuel, Including Transportation

TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include price adjustment components that will affect the future cost.

In January 2016, the existing coal sale agreement for San Juan terminated and a new Coal Supply Agreement (CSA) became effective. The new CSA is between San Juan Coal Company (SJCC) and Public Service Company of New Mexico (PNM) and continues through June 2022. TEP is not a party to the new CSA, but has minimum purchase obligations under restructured ownership agreements at San Juan.

In April 2016, Peabody Energy Corp. (Peabody) filed for reorganization under Chapter 11 of the Bankruptcy Code. TEP has existing contracts with Peabody to supply coal from the El Segundo and Lee Ranch mines to Springerville and from the Kayenta mine to Navajo Generating Station (Navajo). TEP has continued to receive its contracted coal as planned and has sufficient access to coal inventory for the near future. TEP cannot currently predict the outcome of this matter or the range of its potential impact on TEP's coal supply from Peabody.

Transmission

TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These contracts expire in various years between 2017 and 2028.

In June 2016, TEP entered into a new firm point-to-point transmission service agreement. The service agreement has a start date of August 2016 and expires in July 2021.

Renewable Power Purchase Agreements

TEP enters into long-term renewable Power Purchase Agreements (PPA) which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. In March 2016, one of these facilities achieved commercial operation. The PPA expires in February 2036. While TEP is not required to make payments under the agreement if power is not delivered, estimated future payments are included in the table above.

TEP's long-term renewable PPAs effectively transfer commodity price risk to TEP creating a variable interest. TEP has determined it is not a primary beneficiary as it lacks the power to direct the activities that most significantly impact the economic performance of the Variable Interest Entities (VIEs). TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

At June 30, 2016, the carrying amount of assets and liabilities in our Condensed Consolidated Balance Sheets that relate to our variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. Our maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, our exposure is mitigated as we would likely recover these costs through cost recovery mechanisms.

CONTINGENCIES

Legal Matters

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts and are described below.

Claims Related to Springerville Generating Station Unit 1

On February 29, 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). The Agreement provides that: (i) TEP will purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million; and (ii) the Third-Party Owners will pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners. Upon completion of the purchase, all outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners will be dismissed with prejudice.

The purchase of the Third-Party Owners' undivided interest in Springerville Unit 1 is subject to, among other things, approval from the FERC and satisfaction of other customary closing conditions. TEP expects the purchase to close in the third quarter of 2016. However, there is no assurance that the settlement will be finalized or that the litigation will not continue. Therefore, at this time 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 claims, TEP cannot determine estimates of the range of loss, if any, at this time. Should the litigation matters continue, TEP intends to continue vigorously defending itself against the claims asserted by the Third-Party Owners and to continue vigorously pursuing the claims it has asserted against the Owner Trustees and Co-Trustees.

The following is the chronological history of the outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners.

In November 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 existing 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 in January 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. In February 2015, the FERC issued an order denying the Third-Party Owners' complaint. In March 2015, the Third-Party Owners filed a request for rehearing in the FERC Action, which the FERC denied in October 2015. In December 2015, the Third-Party Owners appealed the FERC’s order denying the Third-Party Owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015, TEP filed an unopposed motion to intervene in the Ninth Circuit appeal.

In December 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). In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged, and the court’s subsequent ruling on the motions, the Third-Party Owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain, and make capital investments in Springerville Unit 1 during the term of the leases and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. The third amended complaint seeks $71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The Third-Party Owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015, the Third-Party Owners filed a motion for summary judgment on their claim that TEP has failed to pay certain of the Third-Party Owners’ claimed expenses.

In December 2014 and January 2015, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent notices to TEP that alleged that TEP had defaulted under the Third-Party Owners’ leases. The notices demanded that TEP pay liquidated damages totaling approximately $71 million. In letters to the Owner Trustees, TEP denied the allegations in the notices.

In April 2015, TEP filed a demand for arbitration with the American Arbitration Association (AAA) seeking an award of the Owner Trustees and Co-Trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015, the Third-Party Owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The Third-Party Owners’ arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the Third-Party Owners’ fees and expenses. TEP and the Third-Party Owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015, the Third-Party Owners filed an amended arbitration demand adding claims that TEP has converted the Third-Party Owners’ water rights and certain emission reduction payments and that TEP is improperly dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. In October 2015, the arbitration panel granted TEP’s motion for interim relief, ordering the Owner Trustees and Co-Trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the Third-Party Owners’ motion for interim relief which had requested that TEP be enjoined from dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling, when economical, the Third-Party Owners’ entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015.

In November 2015, TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming the Owner Trustee and Co-Trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015, the Owner Trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order.

As of June 30, 2016, TEP has billed the Third-Party Owners approximately $35 million for their pro-rata share of Springerville Unit 1 expenses and $7 million for their pro-rata share of capital expenditures, none of which had been paid as of July 28, 2016.

Claims Related to San Juan Generating Station

Bureau of Land Management

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 owns 50% of Units 1 and 2 at 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 predict the final outcome of the BLM’s proposed regulations.

WildEarth Guardians

In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District 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 the 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 the OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against the OSM, including, but not limited to, the 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 the 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 the NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. SJCC was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now proceeding. On July 18, 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM may prepare a new environmental impact statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. The motion also requests that the previously-granted mining plan modification approvals for the San Juan mine remain in effect and mining be allowed to continue during the completion of the EIS, and that the case be dismissed. SJCC joined in the motion. 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.

Claims Related to Four Corners Generating Station

New Mexico Taxation and Revenue Department

In May 2013, the New Mexico Taxation and Revenue Department (NMTRD) issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners Generating Station (Four Corners). TEP's share of the assessment is $1 million based on our ownership percentage. 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. In June 2015, the U.S. District Court for the District of New Mexico ruled in favor of the Four Corners' participants. The NMTRD filed an appeal of the decision in August 2015. In March 2016, the coal supplier at Four Corners reached a final settlement agreement with the NMTRD. TEP's share of the final settlement was less than $1 million.

Endangered Species Act

On April 20, 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Arizona against the OSM and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s (DOI) review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the adjacent Navajo mine. In addition, the lawsuit alleges that these federal agencies violated both the ESA and the NEPA in providing the federal approvals necessary to extend operations at Four Corners and the Navajo mine past July 6, 2016. The lawsuit seeks various forms of relief, including a finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo mine pending compliance with NEPA. The defendants answered the complaint on July 8, 2016. Arizona Public Service Company (APS), the operator of Four Corners, filed a motion to intervene in this matter in July 2016. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Generating Station Lease Amendment

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 in 2013 that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment because certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations between the participants 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 DOI, and is subject to environmental reviews. Once the lease amendment becomes effective, the participants will be responsible for additional lease costs from the date the Navajo Nation signed the lease amendment. TEP owns 7.5% of Navajo. In the first six months of 2016, TEP recorded additional estimated lease expense of $1 million with the expectation that the lease amendment will become effective. TEP's Condensed Consolidated Balance Sheets reflect a total lease amendment liability recorded in Regulatory and Other Liabilities—Other of $4 million at June 30, 2016 and $3 million at December 31, 2015.

Mine Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation mine costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine 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 $42 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. TEP's Condensed Consolidated Balance Sheets reflect a total liability related to reclamation of $24 million at June 30, 2016 and $25 million at December 31, 2015.

Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. 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 mine reclamation costs, as a component of fuel costs, 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.

FERC Compliance

In 2015, TEP self-reported to the FERC Office of Enforcement (OE) that TEP had not timely filed certain FERC-jurisdictional agreements. At that time, TEP conducted a comprehensive internal review of its compliance with the FERC filing requirements (Compliance Review), and made necessary compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TEP TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard form of service agreement. The results of the Compliance Review were reported to OE, which is still reviewing the matter.

In April 2016, the FERC issued the FERC Refund Order relating to the late-filed TSAs, which directs TEP to issue time value refunds to the relevant counterparties to these TSAs, in an amount up to $13 million. In March 2016, as a result of the FERC Refund Order, TEP accrued $13 million offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income. As specified in the FERC Refund Order, TEP reviewed its calculations of the ordered refunds and determined the refund amount to be $3 million, which was paid to the relevant counterparties in June 2016. TEP filed a refund report with the FERC on July 8, 2016. The amount of refunds paid is subject to final approval by the FERC and may be modified if the FERC does not accept TEP’s refund report. The remaining accrued balance is reflected in Current Liabilities—Other at June 30, 2016.

In June 2016, to preserve its rights, TEP petitioned the D.C. Circuit Court of Appeals to review the FERC Refund Order. On July 11, 2016, TEP filed an unopposed motion to hold the appeal in abeyance, which the Court has since granted. The FERC could also impose civil penalties on TEP as a result of the OE's review of the Compliance Review. At this time, TEP cannot predict the outcome of these matters or the range of potential penalties, if any.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and the Luna Energy Facility (Luna). The participants in each of the generating stations, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, the non-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 participant. At June 30, 2016, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046.

Environmental Matters

TEP is subject to federal, state, and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in material compliance with all applicable environmental laws and regulations.

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Net periodic benefit plan cost includes the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	3		$	3		$	1		$	1
Interest Cost	3			4			1			1
Expected Return on Plan Assets	(6		)	(6		)	(1		)	(1		)
Amortization of Net Loss (Gain)	2			2			—			—
Net Periodic Benefit Cost	$	2		$	3		$	1		$	1

	Six Months Ended June 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	6		$	6		$	2		$	2
Interest Cost	7			8			1			2
Expected Return on Plan Assets	(12		)	(12		)	(1		)	(1		)
Amortization of Net Loss (Gain)	4			4			—			—
Net Periodic Benefit Cost	$	5		$	6		$	2		$	3

CONTRIBUTIONS

TEP contributed $2 million in the six months endedJune 30, 2016 to the pension plans and expects to contribute a total of $8 million in 2016.

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SUPPLEMENTAL CASH FLOW INFORMATION

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Six Months Ended June 30,
(in millions)	2016		2015
Accrued Capital Expenditures	$	11	$	23
Net Cost of Removal of Interim Retirements (1)	—		(3		)

⁽¹⁾  The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings.

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

6 Months Ended

Jun. 30, 2016

Disclosure Text Block [Abstract]

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our financial instruments 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.

	Level 1		Level 2			Level 3			Total
(in millions)	June 30, 2016
Assets
Cash Equivalents(1)	$	23	$	—		$	—		$	23
Restricted Cash(1)	4		—			—			4
Energy Derivative Contracts - Regulatory Recovery(2)	—		2			—			2
Energy Derivative Contracts - No Regulatory Recovery(2)	—		—			4			4
Total Assets	27		2			4			33
Liabilities
Energy Derivative Contracts - Regulatory Recovery(2)	—		(4		)	(1		)	(5		)
Interest Rate Swap(3)	—		(3		)	—			(3		)
Total Liabilities	—		(7		)	(1		)	(8		)
Net Total Assets (Liabilities)	$	27	$	(5	)	$	3		$	25

(in millions)	December 31, 2015
Assets
Cash Equivalents(1)	$	33	$	—		$	—		$	33
Restricted Cash(1)	4		—			—			4
Energy Derivative Contracts - Regulatory Recovery(2)	—		1			—			1
Energy Derivative Contracts - No Regulatory Recovery(2)	—		—			1			1
Total Assets	37		1			1			39
Liabilities
Energy Derivative Contracts - Regulatory Recovery(2)	—		(10		)	(3		)	(13		)
Interest Rate Swap(3)	—		(3		)	—			(3		)
Total Liabilities	—		(13		)	(3		)	(16		)
Net Total Assets (Liabilities)	$	37	$	(12	)	$	(2	)	$	23

⁽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 Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property on the Condensed Consolidated Balance Sheets.

⁽²⁾  Energy Contracts include gas swap agreements (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. The valuation techniques are described below.

⁽³⁾  The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We present derivatives on a gross basis in the Condensed Consolidated Balance Sheets. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	June 30, 2016
Derivative Assets
Energy Derivative Contracts	$	6		$	2		$	—	$	4
Derivative Liabilities
Energy Derivative Contracts	(5		)	(2		)	—		(3		)
Interest Rate Swap	(3		)	—			—		(3		)

(in millions)	December 31, 2015
Derivative Assets
Energy Derivative Contracts	$	2		$	1		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(13		)	(1		)	—		(12		)
Interest Rate Swap	(3		)	—			—		(3		)

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.

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.

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 can enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. We have an interest rate swap agreement that expires January 2020. We also had a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement which expired in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The loss expected to be reclassified to earnings withinthe next twelve months is estimated to be $1 million.

The realized losses from our cash flow hedges are shown in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Capital Lease Interest Expense	$	—	$	—	$	1	$	1

At June 30, 2016, the total notional amount of our interest rate swap was $23 million.

Energy Derivative Contracts - Regulatory Recovery

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$	12	$	8	$	9	$	2

Energy Derivative 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. The unrealized gains and losses on the long-term power trading contracts are recorded in the income statement, and 10% of any gains will be shared with ratepayers through the PPFAC, as realized.

Derivative Volumes

At June 30, 2016, we have energy contracts that will settle through 2019. The volumes associated with our energy contracts were as follows:

	June 30, 2016	December 31, 2015
Power Contracts GWh	3,832	1,752
Gas Contracts GBtu	13,601	17,214

Level 3 Fair Value Measurements

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

	Valuation	Fair Value of						Range of
	Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
(in millions)	June 30, 2016
Forward Power Contracts	Market approach	$	4	$	(1	)	Market price per MWh	$	21.40	$	36.40
Level 3 Energy Contracts		$	4	$	(1	)

(in millions)	December 31, 2015
Forward Power Contracts	Market approach	$	1	$	(2	)	Market price per MWh	$	19.20		$	31.35
Gas Option Contracts	Option model	—		(1		)	Market price per MMBtu	$	2.17		$	2.69
							Gas volatility	31.0		%	58.3		%
Level 3 Energy Contracts		$	1	$	(3	)

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, 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 table presents a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2016			2015			2016			2015
Beginning of Period	$	(3	)	$	(12	)	$	(2	)	$	(9	)
Gains (Losses) Recorded to: (1)
Regulatory Assets or Liabilities – Derivative Instruments	3			2			2			—
Wholesale Revenues	3			3			3			3
Settlements	—			3			—			2
End of Period	$	3		$	(4	)	$	3		$	(4	)

⁽¹⁾  Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $6 million for both the three months ended June 30, 2016 and 2015 and $6 million and $3 million, for the six months endedJune 30, 2016 and 2015, respectively.

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 TEP and its counterparties 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, or our counterparties, would have to provide certain credit enhancements in the form of cash, a Letter of Credit (LOC), or other acceptable security to collateralize exposure beyond the allowed amounts.

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 June 30, 2016, the value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $15 million, compared with $20 million at December 31, 2015. At June 30, 2016, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on June 30, 2016, TEP would have been required to post an additional $15 million of collateral of which $13 million relates to outstanding net payable balances for settled positions.

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:

• Borrowings under revolving credit facilities 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 following table includes the face value and estimated fair value of our long-term debt:

	Fair Value Hierarchy	Face Value				Fair Value
(in millions)		June 30, 2016		December 31, 2015		June 30, 2016		December 31, 2015
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,466	$	1,466	$	1,541	$	1,529

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

6 Months Ended

Jun. 30, 2016

Disclosure Text Block [Abstract]

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

We consider the applicability and impact of all Accounting Standards Updates issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position, results of operations, or disclosures.

REVENUE FROM CONTRACTS WITH CUSTOMERS

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. In July 2015, the FASB voted to defer the effective date of the revenue recognition standard by one year. We are required to adopt the new guidance for annual and interim periods beginning January 1, 2018.

Retail sales of electricity based on regulator-approved tariff rates represent TEP's primary source of revenue. While it is expected that tariff-based sales to regulated customers are within the scope of the new standard, this question is being reviewed by the AICPA Financial Reporting Executive Committee. TEP is in the process of assessing its performance obligations in its wholesale contracts and identifying other contracts with customers.

CLASSIFICATION AND MEASUREMENT OF FINANCIAL INSTRUMENTS

In January 2016, the FASB amended the guidance on the classification and measurement of financial instruments. Most notably, the new accounting standards update requires the following:

• all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and

• financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset.

TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2018. TEP is evaluating the impact of this guidance to our financial statements and disclosures.

LEASES

In February 2016, the FASB issued an accounting standards update that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under previous GAAP. The standard is effective for periods beginning January 1, 2019 and is to be applied using a modified retrospective approach with practical expedient options; early adoption is permitted. TEP is evaluating the impact of this update to our financial statements and disclosures.

SHARE-BASED COMPENSATION

In March 2016, the FASB issued an accounting standards update that simplifies some provisions in stock compensation accounting. The update involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendment:

• requires that all excess tax benefits and tax deficiencies for share-based payment awards be recognized as income tax expense or benefit in the income statement;

• specifies presentation on the statement of cash flows, and

• requires an accounting policy election to estimate the number of awards that are expected to vest or account for forfeitures when they occur.

TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP is evaluating the impact of this update to our financial statements and disclosures.

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis Of Presentation

BASIS OF PRESENTATION

We prepared our condensed consolidated financial statements according to Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. 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 in 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 and should be read in conjunction with the consolidated financial statements and footnotes in our 2015 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 operating results are not indicative of annual operating results.

Certain amounts from prior periods have been reclassified to conform to the current period presentation.

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REGULATORY MATTERS (Tables)

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

Purchased Power and Fuel Adjustment Clause

The table below presents TEP's PPFAC rates approved by the ACC:

Period	Cents per kWh
May 2016 through March 2017 (1)	0.15
April 2015 through April 2016	0.68
October 2014 through March 2015 (2)	0.50

⁽¹⁾  In April 2016, the ACC approved the PPFAC rate adjustment effective May 2016.

⁽²⁾  The ACC approved a new rate effective October 2014.

Schedule of Regulatory Assets and Liabilities

The regulatory assets and liabilities recorded in the Condensed Consolidated Balance Sheets are summarized in the table below:

(in millions)	Remaining Recovery Period (years)	June 30, 2016		December 31, 2015
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	116	$	120
Final Mine Reclamation and Retiree Health Care Costs (1)	21	30		28
Property Tax Deferrals	1	22		21
Income Taxes Recoverable through Future Rates	Various	22		26
Lost Fixed Cost Recovery	1	21		16
Springerville Unit 1 Leasehold Improvements - Third-Party Owners (2)	7	19		21
Sundt Coal Handling Facilities (3)	Plant Life	17		—
Derivatives (Note 8)	3	3		12
Other Regulatory Assets	Various	19		20
Total Regulatory Assets		269		264
Less Current Portion	1	56		52
Total Non-Current Regulatory Assets		$	213	$	212

Regulatory Liabilities
Net Cost of Removal for Interim Retirements (4)	Various	$	263	$	264
Purchased Power and Fuel Adjustment Clause	1	34		18
Deferred Investment Tax Credits	Various	32		32
Renewable Energy Standard	Various	25		25
Other Regulatory Liabilities	Various	19		21
Total Regulatory Liabilities		373		360
Less Current Portion	1	68		53
Total Non-Current Regulatory Liabilities		$	305	$	307

⁽¹⁾  Final Mine Reclamation and Retiree Health Care Costs are recognized at future value. TEP will fully recover these costs through the PPFAC when paid. The majority of our final mine reclamation costs are expected to occur through 2037.

⁽²⁾  Springerville Unit 1 Leasehold Improvements represent investments TEP made, previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10-year amortization period.

⁽³⁾  In June 2014, the Environmental Protection Agency (EPA) issued a final rule that would require TEP to either: (i) install, by mid-2017, Selective Non-Catalytic Reduction (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-Best Available Retrofit Technology (BART) alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered NBV in its 2015 Rate Case.

⁽⁴⁾  Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

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RELATED PARTY TRANSACTIONS (Table)

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Schedule of Related Party Balances and Transactions

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	June 30, 2016		December 31, 2015
Receivables from Related Parties
UNS Electric	$	4	$	6
UNS Gas	1		1
Total Due from Related Parties	$	5	$	7
Payables to Related Parties
SES	$	2	$	2
UNS Energy	1		2
UNS Electric	—		2
Total Due to Related Parties	$	3	$	6

The following table presents the related party transactions included in the Condensed Consolidated Statements of Income:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Goods and Services Provided by TEP to Affiliates
Transmission Revenues - UNS Electric (1)	$	2	$	2	$	3	$	3
Wholesale Revenues - UNS Electric (1)	—		—		—		1
Control Area Services - UNS Electric (2)	1		—		1		1
Common Costs - UNS Energy Affiliates (3)	4		3		7		6
Goods and Services Provided by Affiliates to TEP
Wholesale Revenues - UNS Electric (1)	$	—	$	—	$	—	$	1
Supplemental Workforce - SES (4)	3		4		7		8
Corporate Services - UNS Energy (5)	2		1		4		2
Corporate Services - UNS Energy Affiliates (6)	2		—		2		—

⁽¹⁾  TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates, through the applicable Open Access Transmission Tariff.

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

⁽³⁾  Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

⁽⁴⁾  SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁵⁾  Costs for corporate services at UNS Energy include Fortis management fees, legal fees, and audit fees which 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 82% of UNS Energy's allocated costs. For the three and six months ended June 30, 2016, these costs included approximately $2 million and $4 million, respectively in Fortis management fees. For the three and six months ended June 30, 2015, Fortis management fees were $1 million and $2 million, respectively.

⁽⁶⁾  Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

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COMMITMENTS AND CONTINGENCIES (Tables)

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments

In addition to those reported in our 2015 Annual Report on Form 10-K, TEP entered into the following long-term commitments through June 30, 2016:

(in millions)	2016		2017		2018		2019		2020		Thereafter		Total
Fuel, Including Transportation	$	21	$	23	$	24	$	24	$	23	$	22	$	137
Transmission	2		4		4		4		4		3		21
Renewable Power Purchase Agreements	3		3		3		3		3		43		58
Total Purchase Commitments	$	26	$	30	$	31	$	31	$	30	$	68	$	216

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EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost

Net periodic benefit plan cost includes the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	3		$	3		$	1		$	1
Interest Cost	3			4			1			1
Expected Return on Plan Assets	(6		)	(6		)	(1		)	(1		)
Amortization of Net Loss (Gain)	2			2			—			—
Net Periodic Benefit Cost	$	2		$	3		$	1		$	1

	Six Months Ended June 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	6		$	6		$	2		$	2
Interest Cost	7			8			1			2
Expected Return on Plan Assets	(12		)	(12		)	(1		)	(1		)
Amortization of Net Loss (Gain)	4			4			—			—
Net Periodic Benefit Cost	$	5		$	6		$	2		$	3

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Six Months Ended June 30,
(in millions)	2016		2015
Accrued Capital Expenditures	$	11	$	23
Net Cost of Removal of Interim Retirements (1)	—		(3		)

⁽¹⁾  The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings.

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2016

Disclosure Text Block [Abstract]

Financial Instruments Measured at Fair Value on 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.

	Level 1		Level 2			Level 3			Total
(in millions)	June 30, 2016
Assets
Cash Equivalents(1)	$	23	$	—		$	—		$	23
Restricted Cash(1)	4		—			—			4
Energy Derivative Contracts - Regulatory Recovery(2)	—		2			—			2
Energy Derivative Contracts - No Regulatory Recovery(2)	—		—			4			4
Total Assets	27		2			4			33
Liabilities
Energy Derivative Contracts - Regulatory Recovery(2)	—		(4		)	(1		)	(5		)
Interest Rate Swap(3)	—		(3		)	—			(3		)
Total Liabilities	—		(7		)	(1		)	(8		)
Net Total Assets (Liabilities)	$	27	$	(5	)	$	3		$	25

(in millions)	December 31, 2015
Assets
Cash Equivalents(1)	$	33	$	—		$	—		$	33
Restricted Cash(1)	4		—			—			4
Energy Derivative Contracts - Regulatory Recovery(2)	—		1			—			1
Energy Derivative Contracts - No Regulatory Recovery(2)	—		—			1			1
Total Assets	37		1			1			39
Liabilities
Energy Derivative Contracts - Regulatory Recovery(2)	—		(10		)	(3		)	(13		)
Interest Rate Swap(3)	—		(3		)	—			(3		)
Total Liabilities	—		(13		)	(3		)	(16		)
Net Total Assets (Liabilities)	$	37	$	(12	)	$	(2	)	$	23

⁽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 Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property on the Condensed Consolidated Balance Sheets.

⁽²⁾  Energy Contracts include gas swap agreements (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. The valuation techniques are described below.

⁽³⁾  The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

Potential Offset of Counterparty Netting and Cash Collateral

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We present derivatives on a gross basis in the Condensed Consolidated Balance Sheets. The tables below present the potential offset of counterparty netting and cash collateral.

	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	June 30, 2016
Derivative Assets
Energy Derivative Contracts	$	6		$	2		$	—	$	4
Derivative Liabilities
Energy Derivative Contracts	(5		)	(2		)	—		(3		)
Interest Rate Swap	(3		)	—			—		(3		)

(in millions)	December 31, 2015
Derivative Assets
Energy Derivative Contracts	$	2		$	1		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(13		)	(1		)	—		(12		)
Interest Rate Swap	(3		)	—			—		(3		)

Realized Losses from Cash Flow Hedges

The realized losses from our cash flow hedges are shown in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Capital Lease Interest Expense	$	—	$	—	$	1	$	1

Financial Impact of Energy Contracts

Energy Derivative Contracts - Regulatory Recovery

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$	12	$	8	$	9	$	2

Derivative Volumes

Derivative Volumes

At June 30, 2016, we have energy contracts that will settle through 2019. The volumes associated with our energy contracts were as follows:

	June 30, 2016	December 31, 2015
Power Contracts GWh	3,832	1,752
Gas Contracts GBtu	13,601	17,214

Level 3 Fair Value Quantitative Information Regarding Unobservable Inputs

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

	Valuation	Fair Value of						Range of
	Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
(in millions)	June 30, 2016
Forward Power Contracts	Market approach	$	4	$	(1	)	Market price per MWh	$	21.40	$	36.40
Level 3 Energy Contracts		$	4	$	(1	)

(in millions)	December 31, 2015
Forward Power Contracts	Market approach	$	1	$	(2	)	Market price per MWh	$	19.20		$	31.35
Gas Option Contracts	Option model	—		(1		)	Market price per MMBtu	$	2.17		$	2.69
							Gas volatility	31.0		%	58.3		%
Level 3 Energy Contracts		$	1	$	(3	)

Level 3 Fair Value Reconciliation of Changes

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2016			2015			2016			2015
Beginning of Period	$	(3	)	$	(12	)	$	(2	)	$	(9	)
Gains (Losses) Recorded to: (1)
Regulatory Assets or Liabilities – Derivative Instruments	3			2			2			—
Wholesale Revenues	3			3			3			3
Settlements	—			3			—			2
End of Period	$	3		$	(4	)	$	3		$	(4	)

⁽¹⁾  Includes gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period of $6 million for both the three months ended June 30, 2016 and 2015 and $6 million and $3 million, for the six months endedJune 30, 2016 and 2015, respectively.

Face Value and Estimated Fair Value of Long-Term Debt

The following table includes the face value and estimated fair value of our long-term debt:

	Fair Value Hierarchy	Face Value				Fair Value
(in millions)		June 30, 2016		December 31, 2015		June 30, 2016		December 31, 2015
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,466	$	1,466	$	1,541	$	1,529

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NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands	6 Months Ended
	Jun. 30, 2016 mi² customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Retail Electric Customers [customer count] | customer	419
Area In Which Company Generates Transmits And Distributes Electricity To Retail Electric Customers [square mile] | mi²	1,155

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REGULATORY MATTERS (Rate Case) (Details) - Arizona Corporation Commission [Member] $ in Millions	1 Months Ended
	Nov. 30, 2015 USD ($)
Public Utilities, General Disclosures [Line Items]
Requested Base Rate Increase Amount	$ 110
Requested Base Rate Increase, Percentage	12.00%
Requested Return on Original Cost Rate Base, Percentage	7.34%
Original Cost Rate Base	$ 2,100

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REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) $ in Millions	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	May 31, 2016 USD ($) proposal	Feb. 29, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) $ / kWh	Jun. 30, 2015 USD ($)	Dec. 31, 2025	Dec. 31, 2016	Dec. 31, 2015
Purchased Power and Fuel Adjustment Clause [Member] | Effective May 2016 Through March 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh					0.0015
Purchased Power and Fuel Adjustment Clause [Member] | Effective April 2015 Through April 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh					0.0068
Purchased Power and Fuel Adjustment Clause [Member] | Effective October 2014 through March 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh					0.0050
Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage									5.00%
Approved Spending Budget	$ 57
Approved Carryover of Unused Funds	9
Approved Recovery of Energy Efficiency Plan	$ 48
Number of Programs Deferred | proposal	2
Renewable Energy Actual Percentage									8.60%
Demand Side Management - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue					$ 2	$ 3
Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Approved Recovery of Energy Efficiency Plan		$ 14
Lost Fixed Cost Recovery Mechanism - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Cap on Increase in Lost Fixed Cost Recovery Rate					1.00%
Recovery Revenue			$ 4	$ 3	$ 9	$ 5
Scenario, Forecast [Member] | Renewable Energy Program [Member]
Public Utilities, General Disclosures [Line Items]
Renewable Energy Target Percentage							15.00%	6.00%
Distributed Generation Requirement Percent of Target Percentage							30.00%

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REGULATORY MATTERS (FERC Matters) (Details) $ in Millions	Apr. 30, 2016 USD ($)
FERC refund order [Member]
Public Utilities, General Disclosures [Line Items]
FERC Time Value Refund Order Amount	$ 13

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REGULATORY MATTERS REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory Assets	$ 269,000	$ 264,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Regulatory Assets, Current	$ 55,787	51,841
Regulatory Assets, Noncurrent	213,403	212,312
Pension and Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Regulatory Assets	116,000	120,000
Final Mine Reclamation and Retiree Health Care Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 30,000	28,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	21 years
Property Tax Deferrals [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 22,000	21,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Income Taxes Recoverable through Future Rates [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 22,000	26,000
Lost Fixed Cost Recovery Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 21,000	16,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Springerville Unit 1 Leasehold Improvements - Third Party Owners [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 19,000	21,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	7 years
Public Utilities, Property, Plant and Equipment, Generation, Useful Life	10 years
Sundt Coal Handling Facilities [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 17,000	0
Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,000	12,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	3 years
Other Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 19,000	$ 20,000

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REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 373,000	$ 360,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Regulatory Liability, Current	$ 68,474	53,077
Regulatory Liability, Noncurrent	304,512	307,286
Net Cost of Removal for Interim Retirements [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	263,000	264,000
Purchased Power and Fuel Adjustment Clause [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 34,000	18,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Deferred Investment Tax Credit [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 32,000	32,000
Renewable Energy Standards [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	25,000	25,000
Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 19,000	$ 21,000

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RELATED PARTY TRANSACTIONS (Receivables From/To and Goods and Services Provided By/To) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts Receivable—Due from Related Parties	$ 5		$ 5		$ 7
Accounts Payable—Due to Related Parties	3		3		6
Transmission Sales To UNS Electric [Member]
Related Party Transaction [Line Items]
Sales to Affiliates	2	$ 2	3	$ 3
Wholesale Sales to UNS Electric [Member]
Related Party Transaction [Line Items]
Sales to Affiliates	0	0	0	1
Tucson Electric Power Company To Uns Electric [Member]
Related Party Transaction [Line Items]
Control Area Services	1	0	1	1
Common Costs Provided to UNS Energy Affiliates [Member]
Related Party Transaction [Line Items]
Common Costs	4	3	7	6
Uns Electric To Tucson Electric Power Company [Member]
Related Party Transaction [Line Items]
Wholesale Sales	0	0	0	1
Supplemental Workforce provided to TEP from SES [Member]
Related Party Transaction [Line Items]
Supplemental Workforce	3	4	7	8
Corporate Services - UNS Energy to TEP [Member]
Related Party Transaction [Line Items]
Corporate Services	2	1	4	2
UNS Energy Affiliates to TEP [Member]
Related Party Transaction [Line Items]
Corporate Services	2	0	2	0
UNS Electric [Member]
Related Party Transaction [Line Items]
Accounts Receivable—Due from Related Parties	4		4		6
Accounts Payable—Due to Related Parties	0		0		2
UNS Gas [Member]
Related Party Transaction [Line Items]
Accounts Receivable—Due from Related Parties	1		1		1
SES [Member]
Related Party Transaction [Line Items]
Accounts Payable—Due to Related Parties	2		2		2
UNS Energy [Member]
Related Party Transaction [Line Items]
Accounts Payable—Due to Related Parties	1		$ 1		$ 2
Massachusetts Formula - TEP's allocation percentage			82.00%
Fortis [Member]
Related Party Transaction [Line Items]
Management fee	$ 2	$ 1	$ 4	$ 2

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RELATED PARTY TRANSACTIONS (Dividend Paid) (Details) - USD ($)		6 Months Ended
	Jul. 27, 2016	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
Dividends Declared		$ 0	$ 0
Dividends Paid		$ 0	$ 0
Subsequent Event [Member]
Related Party Transaction [Line Items]
Dividends Declared	$ 20,000,000
Dividends Paid	$ 20,000,000

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Details) - Springerville Coal Handling Facilities [Member] - Tri-State [Member] - USD ($) $ in Millions	Jun. 30, 2016	Apr. 30, 2015
Capital Lease Asset Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		17.05%
Asset Purchase Option Amount		$ 24
Utility Plant, Proportionate Ownership Share Held for Sale	17.05%

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COMMITMENTS AND CONTINGENCIES (COMMITMENTS) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) facility
Unrecorded Unconditional Purchase Obligation [Line Items]
2016	$ 26
2017	30
2018	31
2019	31
2020	30
Thereafter	68
Total	216
Fuel, Including Transportation [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2016	21
2017	23
2018	24
2019	24
2020	23
Thereafter	22
Total	137
Transmission Facilities [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2016	2
2017	4
2018	4
2019	4
2020	4
Thereafter	3
Total	21
Renewable Power Purchase Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2016	3
2017	3
2018	3
2019	3
2020	3
Thereafter	43
Total	$ 58
Percentage of certain renewable energy generation facilities output required to be purchased by TEP once commercial operation status achieved	100.00%
Number of facilities which achieved commercial operation status in the first three months of 2016 | facility	1

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COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Detail) - USD ($)	1 Months Ended			6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Feb. 29, 2016	Jun. 30, 2016	Jul. 28, 2016	Apr. 30, 2016	Dec. 31, 2015
Commitments And Contingencies [Line Items]
Share of Defaulting Participants' Payment on Performance Guarantees	$ 0			$ 0
FERC refund order [Member]
Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss						$ 13,000,000
Loss Contingency, Accrual, Current		$ 13,000,000
Loss Contingency Accrual, Payments	3,000,000
Springerville Unit One [Member] | Springerville Unit 1 Third Party Owner Allegation [Member] | Pending Settlement [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station			50.50%
Purchase Obligation for Third-Party Owner's undivided interest in Springerville Unit 1			$ 85,000,000
Settlement Amount			$ 12,500,000
Loss Contingency, Damages Sought, Value				71,000,000
Accounts Receivable—Other	35,000,000			35,000,000
Receivable for Capital	$ 7,000,000			$ 7,000,000
Springerville Unit One [Member] | Springerville Unit 1 Third Party Owner Allegation [Member] | Pending Settlement [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Amount paid by Spr Unit 1 Third Party Owners					$ 0
San Juan [Member] | Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member] | Pending Litigation [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station	50.00%			50.00%
Loss Contingency, Damages Sought, Value				$ 5,000,000
Loss Contingency, Estimate of Possible Loss	$ 1,000,000			$ 1,000,000
Approximate percentage of the generation capacity of the station	20.00%			20.00%
Four Corner [Member] | Coal Severance Tax, Penalties, and Interest Assessed to Coal Supplier [Member]
Commitments And Contingencies [Line Items]
Settlement Amount		$ 1,000,000
Loss Contingency, Damages Sought, Value				$ 30,000,000
Loss Contingency, Estimate of Possible Loss	$ 1,000,000			$ 1,000,000
Navajo [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station	7.50%			7.50%
Loss Contingency Accrual, Provision				$ 1,000,000
Loss Contingency, Accrual, Current	$ 4,000,000			4,000,000			$ 3,000,000
Navajo, San Juan, Four Corners [Member]
Commitments And Contingencies [Line Items]
TEP's share of reclamation costs at expiration dates of the coal supply agreements				42,000,000
Reclamation liability reflected in balance sheets	$ 24,000,000			$ 24,000,000			$ 25,000,000

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EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 3	$ 3	$ 6	$ 6
Interest Cost	3	4	7	8
Expected Return on Plan Assets	(6)	(6)	(12)	(12)
Amortization of Net Loss/(Gain)	2	2	4	4
Net Periodic Benefit Cost	2	3	5	6
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1	2	2
Interest Cost	1	1	1	2
Expected Return on Plan Assets	(1)	(1)	(1)	(1)
Amortization of Net Loss/(Gain)	0	0	0	0
Net Periodic Benefit Cost	$ 1	$ 1	$ 2	$ 3

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EMPLOYEE BENEFIT PLANS (CONTRIBUTIONS) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Compensation and Retirement Disclosure [Abstract]
Total Contributions to the Pension Plans Year to Date	$ 2
Total Expected Contributions to Pension Plans in Current Year	$ 8

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SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Other Noncash Investing and Financing Items [Abstract]
Accrued Capital Expenditures	$ 11	$ 23
Net Cost of Removal of Interim Retirements	$ 0	$ (3)

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets
Cash Equivalents	$ 23	$ 33
Restricted Cash	4	4
Derivative Contract Assets - Regulatory Recovery	2	1
Energy Derivative Contract Assets - No Regulatory Recovery	4	1
Total Assets	33	39
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(5)	(13)
Interest Rate Swap	(3)	(3)
Total Liabilities	(8)	(16)
Net Total Assets (Liability)	25	23
Level 1 [Member]
Assets
Cash Equivalents	23	33
Restricted Cash	4	4
Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	27	37
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Interest Rate Swap	0	0
Total Liabilities	0	0
Net Total Assets (Liability)	27	37
Level 2 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Derivative Contract Assets - Regulatory Recovery	2	1
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	2	1
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(4)	(10)
Interest Rate Swap	(3)	(3)
Total Liabilities	(7)	(13)
Net Total Assets (Liability)	(5)	(12)
Level 3 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	4	1
Total Assets	4	1
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(1)	(3)
Interest Rate Swap	0	0
Total Liabilities	(1)	(3)
Net Total Assets (Liability)	$ 3	$ (2)

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Energy Related Derivative [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Asset, Fair Value, Gross Amount Recognized on the Balance Sheets	$ 6	$ 2
Derivative Asset, Counterparty Netting	2	1
Collateral Received	0	0
Derivative Asset, Net Amount	4	1
Derivative Liability, Fair Value, Gross Amount Recognized on the Balance Sheets	(5)	(13)
Derivative Liability, Counterparty Netting	(2)	(1)
Collateral Posted	0	0
Derivative (Liability), Net Amount	(3)	(12)
Interest Rate Swap [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Liability, Fair Value, Gross Amount Recognized on the Balance Sheets	(3)	(3)
Derivative Liability, Counterparty Netting	0	0
Collateral Posted	0	0
Derivative (Liability), Net Amount	$ (3)	$ (3)

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Derivative [Line Items]
Cash Flow Hedge Loss to be Reclassified within Twelve Months	$ 1
Interest Rate Swap [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Swap	$ 23

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cash Flow Hedge Realized Loss - Capital Lease Interest Expense	$ 855	$ 1,007	$ 1,713	$ 2,012
Interest Rate Swap [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cash Flow Hedge Realized Loss - Capital Lease Interest Expense	$ 0	$ 0	$ 1,000	$ 1,000

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Percent of gains shared with ratepayers			10.00%
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$ 12	$ 8	$ 9	$ 2

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Jun. 30, 2016 GWh BTU	Dec. 31, 2015 GWh BTU
Power Contracts (in GWh) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | GWh	3,832	1,752
Gas Contracts (in Btu) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | BTU	13,601,000,000	17,214,000,000

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) - Level 3 [Member] $ in Millions	Jun. 30, 2016 USD ($) $ / megawatt_hour	Dec. 31, 2015 USD ($) $ / MMBTU $ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$ 4	$ 1
Derivative Liabilities	(1)	(3)
Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	4	1
Derivative Liabilities	$ (1)	(2)
Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets		0
Derivative Liabilities		$ (1)
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / megawatt_hour	21.40	19.20
Minimum [Member] | Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / MMBTU		2.17
Gas volatility		31.00%
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / megawatt_hour	36.40	31.35
Maximum [Member] | Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / MMBTU		2.69
Gas volatility		58.30%

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning balance	$ (3,000,000)	$ (12,000,000)	$ (2,000,000)	$ (9,000,000)
Gains/(Losses) Recorded to:
Gains/(Losses) Recorded to Net Regulatory Assets/Liabilities - Derivative Instruments	3,000,000	2,000,000	2,000,000	0
Wholesale Revenues	3,000,000	3,000,000	3,000,000	3,000,000
Settlements	0	3,000,000	0	2,000,000
Ending balance	3,000,000	(4,000,000)	3,000,000	(4,000,000)
Change in Unrealized Gains (Losses) relating to Assets (Liabilities) still held	6,000,000	6,000,000	6,000,000	3,000,000
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale	$ 15,000,000	$ 20,000,000
Additional collateral required to post if credit-risk contingent features are triggered	15,000,000
Accounts Payable and Accrued Liabilities [Member]
Derivative [Line Items]
Additional collateral required to post if credit-risk contingent features are triggered	13,000,000
Line of Credit Collateral [Member]
Derivative [Line Items]
LOCs	$ 0

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Including Current Maturities, Face Value	$ 1,466	$ 1,466
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities, Fair Value	$ 1,541	$ 1,529