TUCSON ELECTRIC POWER CO - FORM 10-Q

Attached files

file	filename
EX-32 - EXHIBIT 32 - TUCSON ELECTRIC POWER CO	tepex3209302016.htm
EX-31.B - EXHIBIT 31.B - TUCSON ELECTRIC POWER CO	tepex31b09302016.htm
EX-31.A - EXHIBIT 31.A - TUCSON ELECTRIC POWER CO	tepex31a09302016.htm
EX-12 - EXHIBIT 12 - TUCSON ELECTRIC POWER CO	tepex1209302016.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2016

¨ 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 o

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 o

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	o	Accelerated Filer	o	Non-accelerated Filer	x	Smaller Reporting Company	o

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



Yes o		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 November 3, 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	40
Accounting Pronouncements	40
Item 3. Quantitative and Qualitative Disclosures about Market Risk	40
Item 4. Controls and Procedures	40

PART II

Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 5. Other Information	41
Item 6. Exhibits	41
Signatures	42
Exhibit Index	43

DEFINITIONS

The abbreviations and acronyms used in the third quarter 2016 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 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
BBtu		Billion British thermal units
CDD		Cooling Degrees Days is 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
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
GAAP		Generally Accepted Accounting Principles in the United States of America,
Gila River		Gila River Generating Station
GWh		Gigawatt-hour(s)
HDD		Heating Degree Days is 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
Luna		Luna Generating Station
MATS		Mercury and Air Toxics Standards
MMBtu		Million British thermal units
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Navajo		Navajo Generating Station
NBV		Net Book Value
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
Springerville Coal Handling Facilities		Coal handling facilities at Springerville used by all four Springerville units

iii



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 Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
TSA		Transmission Service Agreement
Tri-State		Tri-State Generation and Transmission Association, Inc.
UES		UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy Corporation, and intermediate holding company established to own the operating companies UNS Electric, Inc. and UNS Gas, Inc.
UNS Electric		UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
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 Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas		UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation

Table of Contents

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Tucson Electric Power 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 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 potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance 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, data breaches, or other challenges to our information security; and the performance of TEP's generating plants.

Table of Contents

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Operating Revenues
Retail	$	320,379		$	337,284		$	780,782		$	803,204
Wholesale	32,151			40,545			80,648			129,681
Other	41,605			30,915			93,668			89,427
Total Operating Revenues	394,135			408,744			955,098			1,022,312
Operating Expenses
Fuel	86,530			91,853			217,444			239,489
Purchased Power	30,031			40,378			71,794			107,785
Transmission and Other PPFAC Recoverable Costs	7,143			7,386			17,633			18,966
Increase to Reflect PPFAC Recovery Treatment	5,091			9,846			19,356			20,627
Total Fuel and Purchased Power	128,795			149,463			326,227			386,867
Operations and Maintenance	88,699			88,155			260,278			256,455
Depreciation	36,565			34,395			108,110			103,347
Amortization	5,558			4,342			16,579			14,523
Taxes Other Than Income Taxes	12,646			12,038			38,376			38,184
Total Operating Expenses	272,263			288,393			749,570			799,376
Operating Income	121,872			120,351			205,528			222,936
Other Income (Deductions)
Interest Income	11			26			78			77
Other Income	1,774			2,408			4,427			4,466
Other Expense	(1,166		)	(983		)	(2,052		)	(2,101		)
Appreciation (Depreciation) in Value of Investments	722			(1,277		)	1,582			(1,036		)
Total Other Income (Deductions)	1,341			174			4,035			1,406
Interest Expense
Long-Term Debt	15,545			15,630			46,522			45,746
Capital Leases	821			991			2,534			3,003
Other Interest Expense	114			125			372			989
Interest Capitalized	(436		)	(781		)	(1,297		)	(1,977		)
Total Interest Expense	16,044			15,965			48,131			47,761
Income Before Income Taxes	107,169			104,560			161,432			176,581
Income Tax Expense	35,556			36,021			49,985			60,787
Net Income	$	71,613		$	68,539		$	111,447		$	115,794

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in thousands)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Comprehensive Income
Net Income	$	71,613	$	68,539	$	111,447	$	115,794
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $155 and $289	247		452
Net of Income Tax Expense of $242 and $583					385		908
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $34 and $38	55		60
Net of Income Tax Expense of $104 and $113					168		181
Total Other Comprehensive Income, Net of Tax	302		512		553		1,089
Total Comprehensive Income	$	71,915	$	69,051	$	112,000	$	116,883

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)



	Nine Months Ended September 30,
	2016			2015
Cash Flows from Operating Activities
Net Income	$	111,447		$	115,794
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	108,110			103,347
Amortization Expense	16,579			14,523
Amortization of Debt Issuance Costs	2,176			2,288
Use of Renewable Energy Credits for Compliance	13,048			16,139
Deferred Income Taxes	49,972			61,083
Pension and Retiree Expense	11,504			13,941
Pension and Retiree Funding	(12,672		)	(28,922		)
Share-Based Compensation Expense	1,571			862
Allowance for Equity Funds Used During Construction	(3,410		)	(3,391		)
FERC Transmission Refund Payable	18,783			—
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(24,743		)	(47,514		)
Materials, Supplies, and Fuel Inventory	8,366			(7,450		)
Regulatory Assets	(7,533		)	17,294
Accounts Payable and Accrued Charges	23,139			15,108
Regulatory Liabilities	21,648			(4,232		)
Other, Net	3,462			(2,801		)
Net Cash Flows—Operating Activities	341,447			266,069
Cash Flows from Investing Activities
Capital Expenditures	(187,678		)	(259,638		)
Purchase, Springerville Coal Handling Facilities Lease Assets	—			(120,312		)
Proceeds from Sale, Springerville Coal Handling Facilities	—			23,656
Purchase, Springerville Unit 1 Assets	(85,000		)	(45,753		)
Purchase Intangibles, Renewable Energy Credits	(31,192		)	(22,672		)
Contributions in Aid of Construction	1,965			5,761
Net Cash Flows—Investing Activities	(301,905		)	(418,958		)
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	—			(208,600		)
Dividend Paid to Parent	(20,000		)	(25,000		)
Payments of Capital Lease Obligations	(14,080		)	(13,464		)
Payment of Debt Issuance/Retirement Costs	—			(2,987		)
Contribution from Parent	—			180,000
Other, Net	(4,107		)	1,659
Net Cash Flows—Financing Activities	(38,187		)	145,627
Net Increase (Decrease) in Cash and Cash Equivalents	1,355			(7,262		)
Cash and Cash Equivalents, Beginning of Period	55,684			74,170
Cash and Cash Equivalents, End of Period	$	57,039		$	66,908

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands)



	September 30,			December 31,
	2016			2015
ASSETS
Utility Plant
Plant in Service	$	5,869,080		$	5,618,435
Utility Plant Under Capital Leases	131,705			131,705
Construction Work in Progress	140,287			102,028
Total Utility Plant	6,141,072			5,852,168
Accumulated Depreciation and Amortization	(2,346,149		)	(2,194,301		)
Accumulated Amortization of Capital Lease Assets	(103,362		)	(99,638		)
Total Utility Plant, Net	3,691,561			3,558,229

Investments and Other Property	41,177			39,569

Current Assets
Cash and Cash Equivalents	57,039			55,684
Accounts Receivable, Net	155,748			136,682
Fuel Inventory	26,849			34,600
Materials and Supplies	94,242			94,003
Regulatory Assets	52,951			51,841
Derivative Instruments	3,976			1,808
Assets Held for Sale, Net	21,550			21,550
Other	15,097			25,904
Total Current Assets	427,452			422,072
Regulatory and Other Assets
Regulatory Assets	218,078			212,312
Derivative Instruments	271			430
Other	38,270			16,866
Total Regulatory and Other Assets	256,619			229,608
Total Assets	$	4,416,809		$	4,249,478

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands)



	September 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 September 30, 2016 and December 31, 2015)	$	1,296,539		$	1,296,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	280,764			189,317
Accumulated Other Comprehensive Loss	(4,011		)	(4,564		)
Total Common Stock Equity	1,566,935			1,474,935
Preferred Stock (No Par Value, 1,000 Shares Authorized, None Outstanding at September 30, 2016 and December 31, 2015)	—			—
Capital Lease Obligations	39,126			55,324
Long-Term Debt, Net	1,452,734			1,451,720
Total Capitalization	3,058,795			2,981,979
Current Liabilities
Current Obligations Under Capital Leases	15,471			14,114
Accounts Payable	95,868			86,274
Accrued Taxes Other than Income Taxes	56,146			37,577
Accrued Employee Expenses	23,419			27,718
Accrued Interest	12,689			14,246
Regulatory Liabilities	76,533			53,077
Customer Deposits	22,162			20,349
Derivative Instruments	3,501			12,174
Other	14,987			7,533
Total Current Liabilities	320,776			273,062
Regulatory and Other Liabilities
Deferred Income Taxes, Net	524,580			468,024
Regulatory Liabilities	302,881			307,286
Pension and Other Postretirement Benefits	114,390			120,336
Derivative Instruments	2,124			4,067
Other	93,263			94,724
Total Regulatory and Other Liabilities	1,037,238			994,437

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	4,416,809		$	4,249,478

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

(Concluded)

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						115,794						115,794
Other Comprehensive Income, Net of Tax									1,089			1,089
Dividend Declared to Parent						(25,000		)				(25,000		)
Contribution from Parent	180,000											180,000
Balances at September 30, 2015	$	1,296,539	$	(6,357	)	$	202,317		$	(4,837	)	$	1,487,662



	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						111,447						111,447
Other Comprehensive Income, Net of Tax									553			553
Dividend Declared to Parent						(20,000		)				(20,000		)
Balances at September 30, 2016	$	1,296,539	$	(6,357	)	$	280,764		$	(4,011	)	$	1,566,935

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

Table of Contents

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 generation 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).

Key provisions of TEP's general rate case include:


•	a non-fuel 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.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7.04% return on original cost rate base. The return on original cost rate base includes a cost of equity component of 9.75% and an average cost of debt component of 4.32%. The non-fuel base rate increase includes the recovery of approximately $15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016. Recovery of these costs had previously been requested through the PPFAC. In addition, the settlement agreement reflects the adoption of TEP's proposed depreciation and amortization rates as well as a reduction in the depreciable life for San Juan Unit 1. The settlement agreement requires the approval of the ACC before new rates can become effective.

Hearings before an Administrative Law Judge (ALJ) were held in September 2016, and a Recommended Opinion and Order (ROO) is expected in the fourth quarter of 2016. TEP requested new rates to be implemented by January 1, 2017.

Issues related to net metering and rate design for distributed generation customers have been deferred to a second phase of this rate case proceeding, which is expected to begin in the first quarter of 2017.

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 Standard

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.

In May 2016, the ACC approved TEP's 2016 RES implementation plan that included a budget of $57 million, which was 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 certain investments in company-owned solar projects; and (iv) various other program costs. The ACC will consider TEP's rooftop solar and community solar programs in the second phase of the 2015 Rate Case, which is expected to begin in the first quarter of 2017.

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 ACC approved a waiver of the 2016 and 2017 residential distributed generation requirement.

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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 for the prior calendar year in the first quarter of each year, with $2 million recorded in 2016 and $3 million in 2015. 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 for new and existing DSM programs. Energy savings realized through the programs will count toward meeting 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 for 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 meeting 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 make an annual filing with the ACC requesting recovery of 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 $5 million and $14 million in the three and nine months ended September 30, 2016, respectively. TEP recorded $3 million and $9 million in the three and nine months ended September 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 August 2016, the Supreme Court vacated the Court of Appeals decision and confirmed the ACC’s decision regarding the rate adjustor at issue.

FERC COMPLIANCE

In April and October 2016, the FERC issued orders relating to certain late-filed transmission service agreements (TSAs), which resulted in TEP accruing a total of $22 million in time value refunds payable to the counterparties. See Note 6 for additional information related to FERC compliance associated with these transmission contracts.

REGULATORY ASSETS AND LIABILITIES

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of the leasehold improvements at Springerville Unit 1 and the coal handling facilities at Sundt, 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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The regulatory assets and liabilities recorded in the Condensed Consolidated Balance Sheets are summarized in the table below:



(in millions)	Remaining Recovery Period (years)	September 30, 2016		December 31, 2015
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	115	$	120
Final Mine Reclamation and Retiree Health Care Costs ⁽¹⁾	21	30		28
Income Taxes Recoverable through Future Rates	Various	28		26
Property Tax Deferrals	1	23		21
Lost Fixed Cost Recovery	1	21		16
Springerville Unit 1 Leasehold Improvements⁽²⁾	7	18		21
Sundt Coal Handling Facilities ⁽³⁾	Plant Life	16		—
Derivatives (Note 9)	3	2		12
Other Regulatory Assets	Various	18		20
Total Regulatory Assets		271		264
Less Current Portion	1	53		52
Total Non-Current Regulatory Assets		$	218	$	212



Regulatory Liabilities
Net Cost of Removal for Interim Retirements ⁽⁴⁾	Various	$	266	$	264
Purchased Power and Fuel Adjustment Clause	1	38		18
Renewable Energy Standard	Various	29		25
Deferred Investment Tax Credits	Various	28		32
Other Regulatory Liabilities	Various	19		21
Total Regulatory Liabilities		380		360
Less Current Portion	1	77		53
Total Non-Current Regulatory Liabilities		$	303	$	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 leasehold improvement costs at Springerville Unit 1 over a 10-year amortization period.

⁽³⁾

In June 2014, the Environmental Protection Agency (EPA) issued a final rule that required TEP to either: (i) install, by mid-2017, Selective Non-Catalytic Reduction (SNCR) and dry sorbent injection if Sundt Unit 4 continued 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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NOTE 3. ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:



(in millions)	September 30, 2016			December 31, 2015
Customer	$	103		$	79
Due from Affiliates (Note 4)	6			7
Unbilled	41			39
Other⁽¹⁾	10			39
Allowance for Doubtful Accounts⁽¹⁾	(4		)	(27		)
Accounts Receivable, Net	$	156		$	137


⁽¹⁾	In September 2016, Accounts Receivable – Other and Allowance for Doubtful Accounts decreased due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 6 for additional information regarding the settlement of the Third-Party Owners' claims.

NOTE 4. 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)	September 30, 2016		December 31, 2015
Receivables from Related Parties
UNS Electric	$	5	$	6
UNS Gas	1		1
Total Due from Related Parties	$	6	$	7

Payables to Related Parties
SES	$	1	$	2
UNS Energy	1		2
UNS Electric	—		2
Total Due to Related Parties	$	2	$	6

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Goods and Services Provided by TEP to Affiliates
Transmission Revenues - UNS Electric ⁽¹⁾	$	2	$	2	$	5	$	4
Wholesale Revenues - UNS Electric ⁽¹⁾	—		—		—		1
Control Area Services - UNS Electric ⁽²⁾	1		1		2		1
Common Costs - UNS Energy Affiliates ⁽³⁾	3		3		10		9

Goods and Services Provided by Affiliates to TEP
Wholesale Revenues - UNS Electric ⁽¹⁾	$	—	$	—	$	—	$	1
Supplemental Workforce - SES ⁽⁴⁾	3		4		10		13
Corporate Services - UNS Energy ⁽⁵⁾	1		1		5		3
Corporate Services - UNS Energy Affiliates ⁽⁶⁾	1		—		3		1


⁽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 nine months ended September 30, 2016, these costs included approximately $1 million and $4 million, respectively, in Fortis management fees. For the three and nine months ended September 30, 2015, Fortis management fees were $1 million and $3 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.

DIVIDENDS PAID

TEP declared and paid a $20 million dividend to UNS Energy in the first nine months of 2016 and a $25 million dividend in the first nine months of 2015.

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

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

CREDIT FACILITY

TEP's revolving credit facility provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million through its original October 2020 maturity. In October 2016, TEP extended the agreement one year to October 2021 as permitted by the credit agreement. The credit facility commitments will be reduced to $217.5 million in the final year of the agreement.

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

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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 September 30, 2016, the 17.05% undivided interest in the Springerville Coal Handling Facilities that Tri-State plans to purchase is classified as Assets Held for Sale on the Condensed Consolidated Balance Sheets.

COVENANT COMPLIANCE

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

NOTE 6. 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 September 30, 2016:



(in millions)	2016		2017		2018		2019		2020		Thereafter		Total
Fuel, Including Transportation	$	21	$	26	$	27	$	27	$	26	$	26	$	153
Transmission	2		4		4		4		4		3		21
Renewable Power Purchase Agreements	3		3		3		3		3		43		58
Total Purchase Commitments	$	26	$	33	$	34	$	34	$	33	$	72	$	232

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 supply 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 the 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.

In September 2016, TEP extended the expiration date of one of its long-term pipeline transportation contracts from March 2017 to March 2022.

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

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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 September 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

In February 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 provided that: (i) TEP would purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million; and (ii) the Third-Party Owners would pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners.

In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the undivided interest in Springerville Unit 1 for $85 million. The purchase increased TEP's total ownership interest to 100%. As also provided for in the Agreement, TEP received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues – Other on the Condensed Consolidated Statements of Income. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice.

Claims Related to San Juan Generating Station

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. On August 31, 2016, the court issued an order granting the federal defendants’ motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provided that, OSM’s decision approving the mining plan will remain in effect during this process. The order further provides that if the EIS is not completed by August 31, 2019, then an

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order vacating the approved mine plan will become immediately effective, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

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 be approximately $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.

Claims Related to Four Corners Generating Station

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. In July 2016, the defendants answered the complaint and Arizona Public Service Company (APS), the operator of Four Corners, filed a motion to intervene in this matter. 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 three and nine months ended September 30, 2016, TEP recorded additional estimated lease expense of less than $1 million and $1 million, respectively, 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 September 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 September 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.

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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.

Gila River Emissions Compliance

In August 2016, Gila River Generating Station (Gila River) received a Notice of Violation from the Maricopa County Air Quality Department (MCAQD) stating the facility failed to monitor emissions during startup and to properly calibrate carbon monoxide monitors. TEP owns 75% of Gila River Unit 3. Gila River has already performed the necessary corrective actions to address the alleged violations. TEP will continue to work with the other participants at Gila River to address the notice. A response from Gila River to MCAQD was submitted in August 2016. TEP cannot currently predict the outcome of this matter or the range of potential loss or fines, if any.

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 compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several 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 the OE, which is still reviewing the matter. The FERC could impose civil penalties on TEP as a result of the OE's review of the Compliance Review.

In April 2016, the FERC issued an order relating to the late-filed TSAs, which directed TEP to issue time value refunds to the counterparties to these TSAs (FERC Refund Order). As a result, TEP accrued $13 million in March 2016 offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income. As authorized in the FERC Refund Order, TEP reviewed its refund calculations including losses incurred as a result of the calculated refunds and determined the refund amount to be $3 million. TEP filed a refund report including the updated calculations with the FERC in July 2016.

In October 2016, in response to TEP's filed refund report, the FERC issued an additional order (October 2016 FERC Order) which: (i) rejected the filed refund report; (ii) directed TEP to recalculate and pay additional time value refunds within 30 days; and (iii) file a revised refund report with the FERC within 30 days thereafter. TEP has the right to seek a rehearing of the October 2016 FERC Order within 30 days of issuance. As a result of the October 2016 FERC Refund Order and ongoing discussions with the OE, TEP accrued an additional $9 million in September 2016, which offsets Wholesale Revenues on the Condensed Consolidated Statements of Income. TEP paid time value refunds of $3 million in the first nine months of 2016 and an additional $14 million in October 2016.

In June 2016, to preserve its rights, TEP petitioned the D.C. Circuit Court of Appeals to review the FERC Refund Order. In July 2016, TEP filed an unopposed motion to suspend the appeal, which the Court has since granted. As a result of the October 2016 FERC Order, TEP intends to pursue the appeal. At this time, TEP cannot predict the outcome of these matters or the range of possible recoveries or additional losses, if any.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and with 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 September 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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NOTE 7. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2016			2015			2016		2015
Service Cost	$	3		$	3		$	1	$	1
Interest Cost	4			5			1		—
Expected Return on Plan Assets	(5		)	(6		)	—		—
Amortization of Net Loss	1			2			—		—
Net Periodic Benefit Cost	$	3		$	4		$	2	$	1



	Nine Months Ended September 30,
(in millions)	2016			2015			2016			2015
Service Cost	$	9		$	9		$	3		$	3
Interest Cost	11			13			2			2
Expected Return on Plan Assets	(17		)	(18		)	(1		)	(1		)
Amortization of Net Loss	5			6			—			—
Net Periodic Benefit Cost	$	8		$	10		$	4		$	4

CONTRIBUTIONS

TEP made contributions to the pension plans of $8 million during the nine months ended September 30, 2016. No additional contributions are planned in 2016.

NOTE 8. 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:



	Nine Months Ended September 30,
(in millions)	2016		2015
Accrued Capital Expenditures	$	16	$	21
Net Cost of Removal of Interim Retirements ⁽¹⁾	3		(2		)
Additions to Utility Plant, Springerville Unit 1 Settlement	5		—


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

NOTE 9. 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.

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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)	September 30, 2016
Assets
Cash Equivalents⁽¹⁾	$	40	$	—		$	—	$	40
Restricted Cash⁽¹⁾	4		—			—		4
Energy Derivative Contracts, Regulatory Recovery⁽²⁾	—		1			—		1
Energy Derivative Contracts, No Regulatory Recovery⁽²⁾	—		—			3		3
Total Assets	44		1			3		48
Liabilities
Energy Derivative Contracts, Regulatory Recovery⁽²⁾	—		(3		)	—		(3		)
Interest Rate Swap⁽³⁾	—		(2		)	—		(2		)
Total Liabilities	—		(5		)	—		(5		)
Net Total Assets (Liabilities)	$	44	$	(4	)	$	3	$	43



(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.

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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
	Gross Amount Recognized in the Balance Sheets			Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted		Net Amount
(in millions)	September 30, 2016
Derivative Assets
Energy Derivative Contracts	$	4		$	1		$	—	$	3
Derivative Liabilities
Energy Derivative Contracts	(3		)	(1		)	—		(2		)
Interest Rate Swap	(2		)	—			—		(2		)



(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: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) 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 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 within the next twelve months is estimated to be $1 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Capital Lease Interest Expense	$	—	$	—	$	1	$	1
Purchased Power	—		1		—		1

At September 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 comprehensive income, as shown in the following table:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$	1	$	4	$	10	$	7

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



	September 30, 2016	December 31, 2015
Power Contracts GWh	3,076	1,752
Gas Contracts BBtu	10,769	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 Approach	Fair Value of					Range of Unobservable Input
	Valuation Approach	Assets		Liabilities		Unobservable Inputs	Range of Unobservable Input
(in millions)	September 30, 2016
Forward Power Contracts	Market approach	$	3	$	—	Market price per MWh	$	19.10	$	37.40

Level 3 Energy Contracts		$	3	$	—



(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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30,						Nine Months Ended September 30,
(in millions)	2016			2015			2016			2015
Beginning of Period	$	3		$	(4	)	$	(2	)	$	(9	)
Gains (Losses) Recorded to: ⁽¹⁾
Regulatory Assets or Liabilities, Derivative Instruments	1			10			3			(3		)
Wholesale Revenues	—			—			3			3
Settlements	(1		)	(6		)	(1		)	9
End of Period	$	3		$	—		$	3		$	—


⁽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 less than $1 million and $(2) million for the three months ended September 30, 2016 and 2015, respectively, and $3 million and $1 million for the nine months ended September 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: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) 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 then allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk on instruments that are in a net liability position, after considering collateral posted, and then allocate the credit risk adjustment to all individual contracts.

Material adverse changes could trigger credit risk-related contingent features. The value of derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $16 million at September 30, 2016, compared with $20 million at December 31, 2015. At September 30, 2016, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on September 30, 2016, TEP would have been required to post an additional $16 million of collateral of which $14 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 fair value 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.

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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)	Fair Value Hierarchy	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,466	$	1,466	$	1,548	$	1,529

NOTE 10. 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 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. TEP does not expect that the adoption of this standard will have a material impact on the measurement of revenue from energy sales to retail customers. TEP is 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. The accounting standards update is expected to have minimal impact 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 current 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 its 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 in the statement of cash flows. The update:

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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 in 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 expects to early adopt this standard in the fourth quarter of 2016, with an effective date of January 1, 2016, and is in the process of determining the impact that the early adoption of this standard will have on its consolidated financial statements and related 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 in the first nine 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: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory factors. Our plans and strategies include:


•	achieving a constructive outcome in our pending rate case proceeding that provides TEP recovery of its 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.

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2016 Operational and Financial Highlights

The first nine 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. In September 2016, the purchase was completed and all asserted claims were dismissed. The Third-Party Owners paid TEP $12.5 million for previously unreimbursed 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.


•	In April and October 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP accruing a total of $22 million in time value refunds payable to the counterparties to these TSAs.


•	In August 2016, TEP, ACC Staff, and other parties to TEP's pending rate case proceeding entered into a partial settlement agreement regarding the revenue requirement. The settlement reflects a non-fuel base rate increase of $81.5 million and a 7.04% return on original cost rate base. The settlement agreement requires the approval of the ACC before new rates can become effective.

RESULTS OF OPERATIONS

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

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

TEP reported net income of $72 million in the third quarter of 2016 compared with $69 million in the third quarter of 2015. The increase of $3 million, or 4.3%, was primarily due to:


•	$8 million in higher revenues related to the Springerville Unit 1 legal settlement. For further information related to the legal settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q;


•	$1 million increase in the value of company owned life insurance due to favorable market conditions; and


•	$1 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.

The increase was partially offset by:


•	$5 million in additional accrued refunds associated with late-filed TSAs; and


•	$2 million in higher depreciation and amortization expenses.

The first nine months of 2016 compared with the first nine months of 2015

TEP reported net income of $111 million in the first nine months of 2016 compared with $116 million in the first nine months of 2015. The decrease of $5 million, or 4.3%, was primarily due to:


•	$13 million in accrued refunds associated with late-filed TSAs; and


•	$6 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.

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The decrease was partially offset by:


•	$8 million in higher revenues related to the Springerville Unit 1 legal settlement. For further information related to the legal settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q;


•	$5 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


•	$2 million from higher LFCR revenues that partially offset lower retail sales.

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Retail Sales and Revenues

Retail Revenues were $320 million in the third quarter of 2016 compared with $337 million in the third quarter of 2015. Retail Margin Revenues (non-GAAP) were $207 million in the third quarter of 2016 compared with $209 million in the third 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 third quarter of 2016 and 2015:



	Three Months Ended September 30,				Increase (Decrease)
	2016		2015		Amount			Percent
Retail Sales by Customer Class (kWh in millions)
Residential	1,344		1,350		(6		)	(0.4	)%
Commercial	627		637		(10		)	(1.6	)%
Industrial	590		607		(17		)	(2.8	)%
Mining	245		279		(34		)	(12.2	)%
Public Authorities	6		6		—			—	%
Total Retail Sales by Class	2,812		2,879		(67		)	(2.3	)%
Retail Revenues (in millions)
Residential	$	101	$	101	$	—		—	%
Commercial	60		61		(1		)	(1.6	)%
Industrial	30		31		(1		)	(3.2	)%
Mining	10		11		(1		)	(9.1	)%
Public Authorities	—		—		—			—	%
Retail Margin Revenues by Class	201		204		(3		)	(1.5	)%
LFCR Revenues	5		3		2			66.7	%
Other Retail Margin Revenues	1		2		(1		)	(50.0	)%
Retail Margin Revenues (non-GAAP) ⁽¹⁾	207		209		(2		)	(1.0	)%
Fuel and Purchased Power Revenues	98		116		(18		)	(15.5	)%
DSM and RES Surcharge Revenues	15		12		3			25.0	%
Total Retail Revenues (GAAP)	$	320	$	337	$	(17	)	(5.0	)%
Average Retail Margin Rate by Class (cents/kWh)
Residential	7.51		7.48		0.03			0.4	%
Commercial	9.57		9.58		(0.01		)	(0.1	)%
Industrial	5.08		5.11		(0.03		)	(0.6	)%
Mining	4.08		3.94		0.14			3.6	%
Public Authorities ⁽²⁾	5.76		5.78		(0.02		)	(0.3	)%
Average Retail Margin Rate by Class	7.15		7.09		0.06			0.8	%
Total Average Retail Margin Rate ⁽³⁾	7.36		7.26		0.10			1.4	%
Average Fuel and Purchased Power Rate	3.49		4.03		(0.54		)	(13.4	)%
Average DSM and RES Surcharge Rate	0.53		0.42		0.11			26.2	%
Total Average Retail Rate	11.38		11.71		(0.33		)	(2.8	)%
Weather Data
Cooling Degree Days
Actual	962		1,033		(71		)	(6.9	)%
10-year Average	1,018		1,001		*			*

* Not meaningful

⁽¹⁾

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

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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, 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 third quarter of 2016 when compared with the same period in 2015, primarily due to a decrease in the PPFAC rate as a result of lower fuel and purchase power costs.

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Retail Revenues were $781 million in the first nine months of 2016 compared with $803 million in the first nine months of 2015. Retail Margin Revenues (non-GAAP) were $500 million in the first nine months of 2016 compared with $497 million in the first nine months 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 nine months of 2016 and 2015:



	Nine Months Ended September 30,				Increase (Decrease)
	2016		2015		Amount			Percent
Retail Sales by Customer Class (kWh in millions)
Residential	2,990		2,954		36			1.2	%
Commercial	1,633		1,635		(2		)	(0.1	)%
Industrial	1,537		1,590		(53		)	(3.3	)%
Mining	743		832		(89		)	(10.7	)%
Public Authorities	23		23		—			—	%
Total Retail Sales by Class	6,926		7,034		(108		)	(1.5	)%
Retail Revenues (in millions)
Residential	$	226	$	223	$	3		1.3	%
Commercial	146		147		(1		)	(0.7	)%
Industrial	80		81		(1		)	(1.2	)%
Mining	27		29		(2		)	(6.9	)%
Public Authorities	1		1		—			—	%
Retail Margin Revenues by Class	480		481		(1		)	(0.2	)%
LFCR Revenues	14		9		5			55.6	%
DSM Performance Bonus	2		3		(1		)	(33.3	)%
Other Retail Margin Revenues	4		4		—			—	%
Retail Margin Revenues (non-GAAP) ⁽¹⁾	500		497		3			0.6	%
Fuel and Purchased Power Revenues	243		270		(27		)	(10.0	)%
DSM and RES Surcharge Revenues	38		36		2			5.6	%
Total Retail Revenues (GAAP)	$	781	$	803	$	(22	)	(2.7	)%
Average Retail Margin Rate by Class (cents/kWh)
Residential	7.56		7.55		0.01			0.1	%
Commercial	8.94		8.99		(0.05		)	(0.6	)%
Industrial	5.20		5.09		0.11			2.2	%
Mining	3.63		3.49		0.14			4.0	%
Public Authorities ⁽²⁾	5.67		5.66		0.01			0.2	%
Average Retail Margin Rate by Class	6.93		6.84		0.09			1.3	%
Total Average Retail Margin Rate ⁽³⁾	7.22		7.07		0.15			2.1	%
Average Fuel and Purchased Power Rate	3.51		3.84		(0.33		)	(8.6	)%
Average DSM and RES Surcharge Rate	0.55		0.51		0.04			7.8	%
Total Average Retail Rate	11.28		11.42		(0.14		)	(1.2	)%
Weather Data
Cooling Degree Days
Actual	1,431		1,516		(85		)	(5.6	)%
10-year Average	1,491		1,481		*			*
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 Retail Revenues, which is

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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 nine months 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.

Wholesale Revenues



	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2016			2015		2016			2015
Long-Term Wholesale	$	6		$	10	$	23		$	29
Short-Term Wholesale	26			24		57			80
Transmission	9			7		23			21
Transmission Refunds ⁽¹⁾	(9		)	—		(22		)	—
Total Wholesale Revenues	$	32		$	41	$	81		$	130


⁽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 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the FERC ordered refunds.

Wholesale Revenues decreased by $9 million, or 22.0%, in the third quarter of 2016 compared with the same period in 2015 primarily due to additional refunds related to the late-filed TSAs.

Wholesale Revenues decreased by $49 million, or 37.7%, in the first nine months of 2016 compared with the same period in 2015 primarily due to the refunds related to the late-filed TSAs and decreased volumes and market prices of both short-term and long-term wholesale sales resulting from unfavorable market conditions.

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

Other Revenues



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Springerville Units 3 and 4 ⁽¹⁾	$	21	$	24	$	59	$	69
Other	21		7		35		20
Total Other Revenues	$	42	$	31	$	94	$	89


⁽¹⁾	Represents revenues and reimbursements to TEP from Tri-State, the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, related to the operation of these generating units.

Other Revenues includes: (i) reimbursements related to Springerville Units 3 and 4; (ii) inter-company revenues from TEP's affiliates, UNS Gas and UNS Electric, for corporate services provided by TEP; and (iii) miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees.

Revenues from Springerville Units 3 and 4 decreased in the third quarter and first nine months of 2016 compared with the same periods in 2015 primarily due to a decrease in reimbursed costs related to planned generation outages in 2015.

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Revenues – Other increased in the third quarter and first nine months of 2016 compared with the same periods in 2015 primarily due to the Springerville Unit 1 legal settlement. For further information related to the Springerville Unit 1 legal settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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 September 30,
(in millions)	2016	2015	2016		2015
Coal-Fired Generation	2,369	2,362	$	53	$	57
Gas-Fired Generation	1,060	885	33		34
Utility Owned Renewable Generation	17	13	—		—
Reimbursed Fuel Expense, Springerville Units 3 and 4 ⁽¹⁾	—	—	1		1
Total Generation	3,446	3,260	87		92
Total Purchased Power	604	915	30		40
Transmission and Other PPFAC Recoverable Costs	—	—	7		7
Increase to Reflect PPFAC Recovery Treatment	—	—	5		10
Total Generation and Purchased Power	4,050	4,175	$	129	$	149
Less Line Losses and Company Use	224	277
Total Power Sold	3,826	3,898


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

Fuel and Purchased Power Expense decreased by $20 million, or 13.4%, in the third 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 (see table below). The decrease was partially offset by the increase in Gas-Fired Generation kWhs.



	Generation and Purchased Power (kWh)		Fuel and Purchased Power Expense
	Nine Months Ended September 30,
(in millions)	2016	2015	2016		2015
Coal-Fired Generation	5,958	6,500	$	139	$	167
Gas-Fired Generation	2,711	1,876	74		68
Utility Owned Renewable Generation	51	49	—		—
Reimbursed Fuel Expense, Springerville Units 3 and 4 ⁽¹⁾	—	—	4		4
Total Generation	8,720	8,425	217		239
Total Purchased Power	1,547	2,711	72		108
Transmission and Other PPFAC Recoverable Costs	—	—	18		19
Increase to Reflect PPFAC Recovery Treatment	—	—	19		21
Total Generation and Purchased Power	10,267	11,136	$	326	$	387
Less Line Losses and Company Use	575	611
Total Power Sold	9,692	10,525


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

Fuel and Purchased Power Expense decreased by $61 million, or 15.8%, in the first nine months of 2016 compared with the same period in 2015 primarily due to the decrease in purchased power volumes, Coal-Fired Generation kWhs, and a decrease in fuel costs per kWh (see table below). The decrease was partially offset by an increase in Gas-Fired Generation kWhs.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
(cents per kWh)	2016	2015	2016	2015
Coal	2.23	2.39	2.34	2.58
Gas	3.07	3.86	2.73	3.61
Purchased Power, Non-Renewable	4.16	3.73	3.11	3.08
Purchased Power, Renewable	6.75	8.67	6.99	10.37
All Sources	3.23	3.58	3.17	3.48

Operations and Maintenance Expense

The table below summarizes the items included in Operations and Maintenance Expense:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Reimbursed Expenses, Springerville Units 3 and 4 ⁽¹⁾	$	15	$	17	$	40	$	49
Reimbursed Expenses, Customer Funded Renewable Energy and DSM Programs ⁽²⁾	9		7		21		17
Other	65		64		199		190
Total Operations and Maintenance Expense	$	89	$	88	$	260	$	256


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


⁽²⁾	These expenses are collected from customers and the corresponding amounts are recorded in Retail Revenue.

There were no significant changes in Operations and Maintenance Expense in the third quarter of 2016 compared with the same period in 2015.

Operations and Maintenance Expense increased by $4 million, or 1.6%, in the first nine months of 2016 compared with the same period in 2015 due to an increase in Other Operations and Maintenance Expense related 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 planned generation outages in 2015, which were 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.

The key provisions of the rate case include:


•	a non-fuel 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, 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%;

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•	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.

In August 2016, TEP, ACC Staff, and other parties to TEP's pending rate case proceeding entered into a partial settlement agreement regarding the revenue requirement. The settlement reflects a non-fuel base rate increase of $81.5 million and a 7.04% return on original cost rate base. The return on original cost rate base includes a cost of equity component of 9.75% and an average cost of debt component of 4.32%. The non-fuel base rate increase includes the recovery of approximately $15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016. Recovery of these costs had previously been requested through the PPFAC. In addition, the settlement agreement reflects the adoption of TEP's proposed depreciation and amortization rates as well as a reduction in the depreciable life for San Juan Unit 1. The settlement agreement requires the approval of the ACC before new rates can become effective.

Hearings before an ALJ were held in September 2016, and a ROO is expected in the fourth quarter of 2016. TEP requested new rates to be implemented by January 1, 2017.

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 September 30, 2016, approximately 52% 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 generation 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.

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 (CPP) on current coal-fired generation facilities; 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 generation plant operations.

Springerville Unit 1

TEP leased Springerville Unit 1 and an undivided one-half interest in certain facilities at Springerville used in common by Springerville Units 1 and 2 under lease agreements accounted for as capital leases. In January 2015, certain leases related to Springerville Unit 1 expired. At that time, TEP purchased a 24.8% undivided ownership interest in Springerville Unit 1 for an aggregate purchase price of $46 million. Following this purchase, TEP owned 49.5% of Springerville Unit 1 and continued to operate the remaining 50.5% on behalf of the Third-Party Owners.

In September 2016, TEP purchased the remaining 50.5% undivided interest in Springerville Unit 1 for $85 million and received $12.5 million for previously unreimbursed operating costs from the Third-Party Owners as part of a settlement agreement.

See Note 6 of 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.

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Potential Plant Retirements

In March 2016, as required by the ACC, TEP filed its 2016 Preliminary Integrated Resource Plan (IRP). A Supplement to the Preliminary IRP was filed on September 30, 2016 with the final 2017 IRP to be filed by April 2017. TEP's Preliminary IRP and Supplement disclose TEP's plan to reduce its overall coal capacity by 170 MW in 2017 and outlines options for further reductions through 2031. TEP's existing generation fleet faces a number of uncertainties related to generation plant participation and final outcomes of state plans for implementing the CPP. Given this uncertainty, TEP may consider options that include changes in generation 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 generation 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 September 30, 2016, the 17.05% undivided interest in the Springerville Coal Handling Facilities that Tri-State plans to buy is classified as Assets Held for Sale on 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 to mining customers have declined by 10.7% in the first nine 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. In the first nine months of 2016, mining customers accounted for 10.7% of TEP's retail sales and 3.5% 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.

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)	September 30, 2016
Cash and Cash Equivalents	$	57
Amount Available under Revolving Credit Facility ⁽¹⁾	250
Total Liquidity	$	307


⁽¹⁾	TEP's revolving credit facility provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million through its original maturity date of October 2020. In October 2016, TEP extended the agreement one year to October 2021. The credit facility commitments will be reduced to $217.5 million in the final year of the agreement.

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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:



	Nine Months Ended September 30,						Increase (Decrease)
(in millions)	2016			2015			Percent
Operating Activities	$	341		$	266		28.2	%
Investing Activities	(302		)	(419		)	(27.9	)%
Financing Activities	(38		)	146			(126.0	)%
Net Increase (Decrease) in Cash	1			(7		)	114.3	%
Cash and Cash Equivalents, Beginning of Period	56			74			(24.3	)%
Cash and Cash Equivalents, End of Period	$	57		$	67		(14.9	)%

Operating Activities

In the first nine months of 2016, net cash flows from operating activities increased by $75 million compared with the same period in 2015 primarily due to a:


•	$43 million decrease in cash paid for fuel and purchased power costs;


•	$16 million decrease in cash paid for pension and retiree funding;


•	$12.5 million increase in cash proceeds related to the settlement of operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners;


•	$10 million decrease in cash paid for operations and maintenance costs of remote generating stations; and


•	$4 million decrease in cash paid for interest on debt and capital leases, net of amounts capitalized.

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

Investing Activities

In the first nine months of 2016, net cash flows used for investing activities decreased by $117 million compared with the same period in 2015 primarily due to a:


•	$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


•	$72 million decrease in cash paid in 2016 for capital expenditures primarily due to construction cost in 2015 of a new 500kV transmission line.

The decrease in net cash flows used for investing activities was partially offset by a:


•	$85 million purchase in September 2016 of a 50.5% undivided ownership interest in Springerville Unit 1 compared to a $46 million purchase in January 2015 of a 24.8% undivided ownership interest in the same generation facility;


•	$24 million in cash proceeds in May 2015 for the sale of a 17.05% undivided ownership interest in Springerville Coal Handling Facilities to SRP;


•	$9 million increase in cash paid in 2016 for the purchase of renewable energy credits; and

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•	$4 million decrease in cash proceeds in 2016 for contributions in aid of construction.

Financing Activities

In the first nine months of 2016, net cash flows from financing activities decreased by $184 million compared with the same period in 2015 primarily due to a:


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


•	$180 million decrease in cash proceeds in 2016 from a UNS Energy equity contribution in June 2015.

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


•	$209 million decrease in cash paid in 2016 for the purchase of $130 million in tax-exempt long-term debt in January 2015, and the retirement of $79 million in long-term debt in August 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 September 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 TEP's revolving credit facility at September 30, 2016.

For details on TEP's credit facility see Note 5 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 plans to raise additional capital in 2016 or 2017. 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 September 30, 2016, TEP’s credit ratings for senior unsecured debt were A3 from Moody’s and BBB+ from S&P Global Ratings.

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

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unused commitments. Also, under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. At September 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 September 30, 2016, TEP had no LOCs as credit enhancements with its 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 nine 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 declared and paid a $20 million dividend to UNS Energy in the first nine months of 2016 and a $25 million dividend in the first nine months of 2015.

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. In June 2016, TEP reached the equity capitalization threshold.

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. In the first nine months of 2016, 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 that occurred in September 2016.

Contractual Obligations

In the first nine months of 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 long-term commitments entered into by TEP through September 30, 2016, as described in Note 6 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 nine months of 2016 and does not expect to make any payments until 2020.

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

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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 Operations and Maintenance 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 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

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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 September 30, 2016, the NBV of TEP's share in San Juan Unit 2 was $99 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. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for developments in the 2015 Rate Case.

Sundt

In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued 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 permanently eliminate coal as a fuel source to comply with the better-than-BART alternative emission limits. See Note 2 of 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 were 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 received an extension are required to submit a final completed plan to the EPA by September 2018.

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 state approved 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.

In September 2016, the D.C. Circuit Court of Appeals heard oral arguments on the CPP, before an en banc court. A decision is not expected until late 2016 or early 2017. 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.

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 operate any impoundments. Under the rule, the 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.

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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 nine months ended September 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 10 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 September 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 nine months ended September 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 6 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 were parties to litigation and arbitration proceedings relating to Springerville Unit 1. In February 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).

In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the undivided interest in Springerville Unit 1 for $85 million, and received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice.

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



	Nine Months Ended	Twelve Months Ended
	September 30, 2016	September 30, 2016
Ratio of Earnings to Fixed Charges	4.16	3.71

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.

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:	November 4, 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)

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.

TUCSON ELECTRIC POWER CO - FORM 10-Q - November 4, 2016

Attached files

TUCSON ELECTRIC POWER CO Reports