TUCSON ELECTRIC POWER CO - FORM 10-Q

Attached files

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EX-32 - EXHIBIT 32 - TUCSON ELECTRIC POWER CO	tepex3209302017.htm
EX-31.B - EXHIBIT 31.B - TUCSON ELECTRIC POWER CO	tepex31b09302017.htm
EX-31.A - EXHIBIT 31.A - TUCSON ELECTRIC POWER CO	tepex31a09302017.htm
EX-12 - EXHIBIT 12 - TUCSON ELECTRIC POWER CO	tepex1209302017.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, 2017

¨ 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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 Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 2, 2017.

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	23
Critical Accounting Policies and Estimates	38
Accounting Pronouncements	38
Item 3. Quantitative and Qualitative Disclosures about Market Risk	38
Item 4. Controls and Procedures	38

PART II

Item 1. Legal Proceedings	40
Item 1A. Risk Factors	40
Item 5. Other Information	40
Item 6. Exhibits	41
Signatures	42

DEFINITIONS

The abbreviations and acronyms used in the third quarter 2017 Form 10-Q are defined below:



2017 Rate Order		A rate order issued by the ACC resulting in a new rate structure for TEP, effective on February 27, 2017
ACC		Arizona Corporation Commission
APS		Arizona Public Service Company
ASU		Accounting Standard Update
BART		Best Available Retrofit Technology
BBtu		Billion British thermal units
Cooling Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DG		Distributed Generation
DSM		Demand Side Management
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)
Heating Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65
kWh		Kilowatt-hour(s)
LFCR		Lost Fixed Cost Recovery
LOC		Letter(s) of Credit
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Navajo		Navajo Generating Station
NBV		Net Book Value
PDEQ		Pima County Department of Environmental Quality
Phase 2		Second phase of TEP's rate case proceedings originally filed November 2015
PNM		Public Service Company of New Mexico
PPA		Power Purchase Agreement
PPFAC		Purchased Power and Fuel Adjustment Clause
Regional Haze Rules		Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
RES		Renewable Energy Standard
Retail Rates		Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
RICE		Reciprocating Internal Combustion Engine
San Juan		San Juan Generating Station
SES		Southwest Energy Solutions, Inc.
SJCC		San Juan Coal Company
Springerville		Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sundt		H. Wilson Sundt Generating Station

iii



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
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
VIE		Variable Interest Entity

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 or the Company) 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, economical, 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, potential, 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 2016 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 and bank markets; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and the related contribution requirements and expenses; 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 (DG) 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, including our operations and technology systems; and the performance of TEP's generating facilities.

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,
	2017			2016			2017			2016
Operating Revenues
Retail	$	340,410		$	320,379		$	820,453		$	780,782
Wholesale	43,868			32,151			130,242			80,648
Other	32,932			41,605			87,041			93,668
Total Operating Revenues	417,210			394,135			1,037,736			955,098
Operating Expenses
Fuel	91,754			86,530			218,226			217,444
Purchased Power	38,903			30,031			107,039			71,794
Transmission and Other PPFAC Recoverable Costs	10,285			7,143			27,167			17,633
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(9,166		)	5,091			(24,773		)	19,356
Total Fuel and Purchased Power	131,776			128,795			327,659			326,227
Operations and Maintenance	89,862			88,699			256,493			260,278
Depreciation	38,302			36,565			114,667			108,110
Amortization	5,463			5,558			16,323			16,579
Taxes Other Than Income Taxes	13,549			12,646			40,329			38,376
Total Operating Expenses	278,952			272,263			755,471			749,570
Operating Income	138,258			121,872			282,265			205,528
Other Income (Deductions)
Interest Income	30			11			556			78
Other Income	1,738			1,774			12,630			4,427
Other Expense	(1,072		)	(1,166		)	(2,609		)	(2,052		)
Appreciation in Value of Investments	912			722			2,130			1,582
Total Other Income (Deductions)	1,608			1,341			12,707			4,035
Interest Expense
Long-Term Debt	15,531			15,545			46,461			46,522
Capital Leases	613			821			1,941			2,534
Other Interest Expense	147			114			570			372
Interest Capitalized	(525		)	(436		)	(1,645		)	(1,297		)
Total Interest Expense	15,766			16,044			47,327			48,131
Income Before Income Taxes	124,100			107,169			247,645			161,432
Income Tax Expense	42,100			35,556			83,951			49,985
Net Income	82,000			71,613			163,694			111,447

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,
	2017		2016		2017		2016
Comprehensive Income
Net Income	$	82,000	$	71,613	$	163,694	$	111,447
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $79 and $155	121		247
Net of Income Tax Expense of $212 and $242					336		385
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $44 and $34	69		55
Net of Income Tax Expense of $130 and $104					209		168
Total Other Comprehensive Income, Net of Tax	190		302		545		553
Total Comprehensive Income	$	82,190	$	71,915	$	164,239	$	112,000

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,
	2017			2016
Cash Flows from Operating Activities
Net Income	$	163,694		$	111,447
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	114,667			108,110
Amortization Expense	16,323			16,579
Amortization of Debt Issuance Costs	1,763			2,176
Use of Renewable Energy Credits for Compliance	17,434			13,048
Deferred Income Taxes	83,954			49,972
Pension and Other Postretirement Benefits Expense	12,029			11,504
Pension and Other Postretirement Benefits Funding	(12,763		)	(12,672		)
Allowance for Equity Funds Used During Construction	(4,145		)	(3,410		)
FERC Transmission Refund Payable	(4,878		)	18,783
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(59,016		)	(24,743		)
Materials, Supplies, and Fuel Inventory	452			8,366
Regulatory Assets	(2,407		)	(7,533		)
Accounts Payable and Accrued Charges	25,628			23,139
Regulatory Liabilities	(10,258		)	21,648
Other, Net	(5,213		)	5,033
Net Cash Flows—Operating Activities	337,264			341,447
Cash Flows from Investing Activities
Capital Expenditures	(215,826		)	(187,678		)
Purchase, Springerville Unit 1 Assets	—			(85,000		)
Purchase Intangibles, Renewable Energy Credits	(40,838		)	(31,192		)
Contributions in Aid of Construction	3,265			1,965
Other, Net	(975		)	—
Net Cash Flows—Investing Activities	(254,374		)	(301,905		)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facilities	35,000			—
Repayments of Borrowings, Revolving Credit Facilities	(35,000		)	—
Dividend Paid to Parent	(35,000		)	(20,000		)
Payments of Capital Lease Obligations	(14,804		)	(14,080		)
Other, Net	641			(4,107		)
Net Cash Flows—Financing Activities	(49,163		)	(38,187		)
Net Increase in Cash and Cash Equivalents	33,727			1,355
Cash and Cash Equivalents, Beginning of Period	35,962			55,684
Cash and Cash Equivalents, End of Period	$	69,689		$	57,039

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)



	September 30, 2017			December 31, 2016
ASSETS
Utility Plant
Plant in Service	$	5,633,029		$	5,975,139
Utility Plant Under Capital Leases	167,413			167,413
Construction Work in Progress	165,139			129,955
Total Utility Plant	5,965,581			6,272,507
Accumulated Depreciation and Amortization	(2,153,176		)	(2,385,053		)
Accumulated Amortization of Capital Lease Assets	(109,743		)	(104,648		)
Total Utility Plant, Net	3,702,662			3,782,806

Investments and Other Property	47,099			45,020

Current Assets
Cash and Cash Equivalents	69,689			35,962
Accounts Receivable, Net	186,007			124,934
Fuel Inventory	23,943			25,887
Materials and Supplies	103,435			97,126
Regulatory Assets	66,899			56,340
Derivative Instruments	4,912			4,966
Other	14,713			13,793
Total Current Assets	469,598			359,008
Regulatory and Other Assets
Regulatory Assets	299,943			225,453
Derivative Instruments	549			330
Other	55,321			37,372
Total Regulatory and Other Assets	355,813			263,155
Total Assets	$	4,575,172		$	4,449,989

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)



	September 30, 2017			December 31, 2016
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2017, and December 31, 2016)	$	1,296,539		$	1,296,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	402,102			273,408
Accumulated Other Comprehensive Loss	(4,010		)	(4,555		)
Total Common Stock Equity	1,688,274			1,559,035
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2017, and December 31, 2016)	—			—
Capital Lease Obligations	28,518			39,267
Long-Term Debt, Net	1,454,085			1,453,072
Total Capitalization	3,170,877			3,051,374
Current Liabilities
Capital Lease Obligations	47,224			51,765
Accounts Payable	95,353			89,797
Accrued Taxes Other than Income Taxes	60,167			37,639
Accrued Employee Expenses	25,034			29,465
Accrued Interest	13,135			14,508
Regulatory Liabilities	66,066			76,069
Customer Deposits	24,676			25,778
Derivative Instruments	4,579			2,641
Other	10,830			17,837
Total Current Liabilities	347,064			345,499
Regulatory and Other Liabilities
Deferred Income Taxes, Net	619,838			529,148
Regulatory Liabilities	205,546			300,700
Pension and Other Postretirement Benefits	125,762			131,630
Derivative Instruments	5,041			2,629
Other	101,044			89,009
Total Regulatory and Other Liabilities	1,057,231			1,053,116

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	4,575,172		$	4,449,989

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 as of 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		)
Adoption of ASU, Cumulative Effect Adjustment						9,653						9,653
Balances as of September 30, 2016	$	1,296,539	$	(6,357	)	$	290,417		$	(4,011	)	$	1,576,588



	Common Stock		Capital Stock Expense			Retained Earnings			Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances as of December 31, 2016	$	1,296,539	$	(6,357	)	$	273,408		$	(4,555	)	$	1,559,035
Net Income						163,694						163,694
Other Comprehensive Income, Net of Tax									545			545
Dividend Declared to Parent						(35,000		)				(35,000		)
Balances as of September 30, 2017	$	1,296,539	$	(6,357	)	$	402,102		$	(4,010	)	$	1,688,274

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 422,000 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).

BASIS OF PRESENTATION

TEP's condensed consolidated financial statements and disclosures are presented in accordance with 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 its proportionate share of Operating Expenses 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 TEP's 2016 Annual Report on Form 10-K.

The condensed consolidated financial statements are unaudited, but, in management's opinion, include all normal, 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, TEP's 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.

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP routinely enters into long-term renewable Power Purchase Agreements (PPA) with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, 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 VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

As of September 30, 2017, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2016, TEP adopted accounting guidance that simplifies the accounting for share-based payment accounting. The guidance requires that excess tax benefits and tax deficiencies be recorded as an income tax benefit or expense on the income statement and eliminates the requirement that excess tax benefits be realized before companies can recognize them. On adoption, using the modified retrospective method of transition, TEP recorded a cumulative effect adjustment of $10 million to increase retained earnings and decrease deferred income taxes related to prior period unrecognized excess tax benefits. The impact on the income and the cash flow statements was not significant. TEP elected to recognize forfeitures when they occur.

Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principle did not have any impact on TEP as the Company recovers the cost of inventory through its rates.

UTILITY PLANT

Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction, less contributions in aid of construction.

Retirements

In March 2017, TEP recorded the early retirement of Unit 2 of the San Juan Generating Station (San Juan) and the coal handling facilities at H. Wilson Sundt Generating Station (Sundt) in accordance with provisions in a rate order issued by the Arizona Corporation Commission (ACC) that took effect February 27, 2017 (2017 Rate Order). The Condensed Consolidated Balance Sheets reflect a: (i) $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2; and (ii) $14 million decrease in Regulatory Assets and Accumulated Depreciation and Amortization related to the coal handling facilities at Sundt. See Note 2 for additional information related to the 2017 Rate Order.

In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo Generating Station (Navajo) to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's net book value (NBV) and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets as of September 30, 2017. See Note 2 for additional information related to the planned early retirement of Navajo.

In August 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of reciprocating internal combustion engines (RICE) in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to the planned early retirement of Sundt Units 1 and 2.

Depreciation

Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). In the 2017 Rate Order, the ACC approved the results of a new depreciation study for TEP. In May 2017, TEP transferred $87 million from Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of the revised depreciation study on the estimated cost of removal. See Note 2 for additional information related to the net cost of removal balance in Regulatory Liabilities.

NOTE 2. REGULATORY MATTERS

The ACC and the FERC each regulate portions of 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.

2017 RATE ORDER

In February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017. Provisions of the 2017 Rate Order include, but are not limited to:


•	a non-fuel base rate increase of $81.5 million, which includes $15 million of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station (Springerville) purchased by TEP in September 2016;

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•	a 7.04% return on original cost rate base, which includes a cost of equity component of 9.75% and a cost of debt component of 4.32%;


•	adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and


•	approval of 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.

The ACC deferred matters related to net metering and rate design for new distributed generation (DG) customers to a second phase of TEP’s rate case (Phase 2), which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of these proceedings.

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 Purchased Power and Fuel Adjustment Clause (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 rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment (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 PPFAC bank balance was over-collected by $20 million as of September 30, 2017 and by $38 million as of December 31, 2016.

In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected balance to customers. The table below presents TEP's PPFAC rates approved by the ACC:



Period	Cents per kWh
March 2017 through March 2018	(0.20	)
May 2016 through February 2017	0.15
April 2015 through April 2016	0.68

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 DG 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 March 2017, the ACC approved TEP's 2017 RES implementation plan with a budget of $54 million, which was partially offset by applying $2 million of previously recovered carryover funds. TEP will recover the remaining $52 million through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer installed DG; and (iii) various other program costs. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case.

The percentage of retail kilowatt-hour (kWh) sales attributable to the RES in 2016 was 11%, which exceeded the overall 2016 RES requirement of 6%. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG renewable energy credits, which are used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2016 and 2017 residential DG requirement.

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 regulated utilities a DSM surcharge to recover the costs to implement DSM programs from retail customers, as well as an annual performance incentive. TEP records its annual DSM

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performance incentive for the prior calendar year in the first quarter of each year, with $2 million recorded in both 2017 and 2016. 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 with a budget of approximately $22 million, which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customers through the DSM surcharge. 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.

In June 2016, TEP notified the ACC that it would not file a 2017 energy efficiency implementation plan and instead continue the 2016 level of recovery through the end of 2017. TEP plans to reduce its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017. TEP filed its 2018 energy efficiency implementation plan in August 2017 and requested the Commission issue an order prior to the end of 2017.

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 customer installed DG. 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 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.

TEP recorded regulatory assets and recognized LFCR revenues of $6 million and $17 million in the three and nine months ended September 30, 2017, respectively, and $5 million and $14 million in the three and nine months ended September 30, 2016, respectively. LFCR revenues are included in Retail Revenues on the Condensed Consolidated Statements of Income.

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REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below:



(dollars in millions)	Remaining Recovery Period (years)	September 30, 2017		December 31, 2016
Regulatory Assets
Pension and Other Postretirement Benefits (Note 7)	Various	$	123	$	128
Early Generation Retirement Costs ⁽¹⁾	Various	83		—
Final Mine Reclamation and Retiree Health Care Costs ⁽²⁾	20	34		27
Income Taxes Recoverable through Future Rates	Various	31		29
Lost Fixed Cost Recovery	1	29		23
Property Tax Deferrals	1	24		23
Springerville Unit 1 Leasehold Improvements⁽³⁾	6	14		17
Sundt Coal Handling Facilities ⁽⁴⁾	N/A	—		14
Other Regulatory Assets	Various	29		20
Total Regulatory Assets		367		281
Less Current Portion	1	67		56
Total Non-Current Regulatory Assets		$	300	$	225



Regulatory Liabilities
Net Cost of Removal ⁽⁵⁾	Various	$	180	$	270
Renewable Energy Standard	Various	43		32
Purchased Power and Fuel Adjustment Clause	1	20		38
Deferred Investment Tax Credits	Various	20		23
Other Regulatory Liabilities	Various	9		14
Total Regulatory Liabilities		272		377
Less Current Portion	1	66		76
Total Non-Current Regulatory Liabilities		$	206	$	301

⁽¹⁾

Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. As of September 30, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 1 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2.


⁽²⁾	Includes costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037.


⁽³⁾	Represents investments TEP made 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.


⁽⁴⁾	The ACC authorized TEP to apply excess depreciation reserves against the unrecovered NBV in the 2017 Rate Order.

⁽⁵⁾

Net Cost of Removal represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal.

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs, TEP does not pay a return on regulatory liabilities.

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FERC COMPLIANCE

In 2016, the FERC issued orders relating to certain late-filed transmission service agreements (TSAs), which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 6 for additional information related to FERC compliance associated with these transmission contracts.

NOTE 3. ACCOUNTS RECEIVABLE

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



(in millions)	September 30, 2017			December 31, 2016
Customer	$	118		$	74
Due from Affiliates (Note 4)	7			9
Unbilled	49			34
Other	18			13
Allowance for Doubtful Accounts	(6		)	(5		)
Accounts Receivable, Net	$	186		$	125

NOTE 4. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including 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, 2017		December 31, 2016
Receivables from Related Parties
UNS Electric	$	5	$	7
UNS Gas	2		2
Total Due from Related Parties	$	7	$	9

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

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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)	2017		2016		2017		2016
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric ⁽¹⁾	$	2	$	2	$	5	$	5
Control Area Services, UNS Electric ⁽²⁾	1		1		2		2
Common Costs, UNS Energy Affiliates ⁽³⁾	4		3		12		10

Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES ⁽⁴⁾	4		3		11		10
Corporate Services, UNS Energy ⁽⁵⁾	1		1		4		5
Corporate Services, UNS Energy Affiliates ⁽⁶⁾	1		1		3		3


⁽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 are deemed reasonable by management.

⁽⁵⁾

Costs for Corporate Services at UNS Energy 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. Corporate Services, UNS Energy includes legal, audit, and Fortis management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and nine months ended September 30, 2017, respectively, and $1 million and $4 million for the three and nine months ended September 30, 2016, 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 TO PARENT

TEP declared and paid a $35 million dividend to UNS Energy in the three and nine months ended September 30, 2017, and a $20 million dividend to UNS Energy in the three and nine months ended September 30, 2016.

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

There have been no significant changes to TEP's debt, credit facility, or capital lease obligations from those reported in its 2016 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 Letter of Credit (LOC) sublimit of $50 million through its original October 2020 maturity. As permitted by the credit facility, in October 2017 TEP requested and was granted the second of its two one-year extensions effectively extending the final maturity date to October 2022.

COVENANT COMPLIANCE

As of September 30, 2017, TEP was in compliance with the terms of its credit and long-term debt agreements.

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NOTE 6. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2016 Annual Report on Form 10-K.

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 believes such normal and routine litigation will not have a material impact on its condensed 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 on TEP and are disclosed below.

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 Office of Surface Mining (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 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 National Environmental Policy Act (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 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. APS’ motion was granted in August 2016. In September 2016, Navajo Transitional Energy Company, LLC (NTEC), the company that owns the Navajo Mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice.

Claims Related to San Juan Generating Station

WildEarth Guardians

In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the OSM challenging several unrelated mining plan modification approvals, including two issued in 2008 related to San Juan Coal Company’s (SJCC) San Juan mine. The petition alleges various NEPA violations against the OSM, including failure to provide requisite public notice and participation, and failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and 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 pending. In July 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. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provided that the OSM’s decision approving the mining plan will remain in effect during this process, but that if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

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). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased

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the Third-Party Owners’ undivided interest in Springerville Unit 1 for $85 million. 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 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.

Mine Reclamation at Generating Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities 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 $61 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The balance sheet reflected a total liability related to reclamation of $32 million as of September 30, 2017 and $26 million as of December 31, 2016.

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

TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

FERC Compliance

In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews) 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 service agreement form.

In 2016, the FERC issued orders related to the late-filed TSAs which directed TEP to issue time-value refunds to the counterparties to these TSAs (FERC Refund Orders). As a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016. For the three and nine months ended September 30, 2016, Wholesale Revenues on the Condensed Consolidated Statements of Income reflected $9 million and $22 million, respectively, related to the time-value refunds. As of December 31, 2016, Current Liabilities—Other on the Condensed Consolidated Balance Sheets reflected $5 million related to the time-value refunds.

In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In accordance with the agreement, the counterparty paid TEP $8 million, which TEP recorded in Other Income on the Condensed Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017.

In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Condensed Consolidated Balance Sheets, offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and with Luna Generating Station (Luna). The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its 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 generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of September 30, 2017, there have been no such payment

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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 environmental 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 condensed consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in material compliance with applicable environmental laws and regulations.

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)	2017			2016			2017			2016
Service Cost	$	3		$	3		$	1		$	1
Interest Cost	3			4			1			1
Expected Return on Plan Assets	(6		)	(5		)	(1		)	—
Amortization of Net Loss	2			1			—			—
Net Periodic Benefit Cost	$	2		$	3		$	1		$	2



	Nine Months Ended September 30,
(in millions)	2017			2016			2017			2016
Service Cost	$	9		$	9		$	3		$	3
Interest Cost	11			11			2			2
Expected Return on Plan Assets	(18		)	(17		)	(1		)	(1		)
Amortization of Net Loss	6			5			—			—
Net Periodic Benefit Cost	$	8		$	8		$	4		$	4

CONTRIBUTIONS

TEP contributed $9 million during the nine months ended September 30, 2017, to the pension plans. No additional contributions are planned in 2017.

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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)	2017			2016
Net Cost of Removal Increase (Decrease) ⁽¹⁾	$	(88	)	$	3
Accrued Capital Expenditures	18			16
Additions to Utility Plant, Springerville Unit 1 Settlement ⁽²⁾	—			5


⁽¹⁾	Non-cash Net Cost of Removal represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information.


⁽²⁾	See Note 6 for additional information regarding the Springerville Unit 1 settlement.

NOTE 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

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



	Level 1		Level 2			Level 3			Total
(in millions)	September 30, 2017
Assets
Cash Equivalents⁽¹⁾	$	59	$	—		$	—		$	59
Restricted Cash⁽¹⁾	8		—			—			8
Energy Derivative Contracts, Regulatory Recovery⁽²⁾	—		—			1			1
Energy Derivative Contracts, No Regulatory Recovery⁽²⁾	—		—			4			4
Total Assets	67		—			5			72
Liabilities
Energy Derivative Contracts, Regulatory Recovery⁽²⁾	—		(7		)	—			(7		)
Energy Derivative Contracts, No Regulatory Recovery⁽²⁾	—		—			(1		)	(1		)
Interest Rate Swap⁽³⁾	—		(1		)	—			(1		)
Total Liabilities	—		(8		)	(1		)	(9		)
Total Assets (Liabilities), Net	$	67	$	(8	)	$	4		$	63

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(in millions)	December 31, 2016
Assets
Cash Equivalents⁽¹⁾	$	23	$	—		$	—		$	23
Restricted Cash⁽¹⁾	7		—			—			7
Energy Derivative Contracts, Regulatory Recovery⁽²⁾	—		3			—			3
Energy Derivative Contracts, No Regulatory Recovery⁽²⁾	—		—			2			2
Total Assets	30		3			2			35
Liabilities
Energy Derivative Contracts, Regulatory Recovery⁽²⁾	—		(2		)	(1		)	(3		)
Interest Rate Swap⁽³⁾	—		(2		)	—			(2		)
Total Liabilities	—		(4		)	(1		)	(5		)
Total Assets (Liabilities), Net	$	30	$	(1	)	$	1		$	30

⁽¹⁾

Cash Equivalents and Restricted Cash represent amounts held in money market funds, insured cash sweep accounts, 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 and in Current Assets—Other on the Condensed Consolidated Balance Sheets.


⁽²⁾	Energy Derivative Contracts include gas swap agreements (Level 2), and forward purchased power 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 London Interbank Offered Rate and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. 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, 2017
Derivative Assets
Energy Derivative Contracts	$	5		$	2		$	—	$	3
Derivative Liabilities
Energy Derivative Contracts	(8		)	(2		)	—		(6		)
Interest Rate Swap	(1		)	—			—		(1		)



(in millions)	December 31, 2016
Derivative Assets
Energy Derivative Contracts	$	5		$	2		$	—	$	3
Derivative Liabilities
Energy Derivative Contracts	(3		)	(2		)	—		(1		)
Interest Rate Swap	(2		)	—			—		(2		)

DERIVATIVE INSTRUMENTS

TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural 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 mechanism.

The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.

For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes 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, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.

TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

The inputs and the Company's 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. TEP reviews the assumptions underlying its price curves monthly.

Cash Flow Hedges

To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020. 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.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2017		2016		2017		2016
Capital Lease Interest Expense	$	—	$	—	$	1	$	1

As of September 30, 2017, the total notional amount of the interest rate swap was $18 million.

Energy Derivative Contracts, Regulatory Recovery

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



	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2017			2016		2017			2016
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$	(1	)	$	1	$	(6	)	$	10

Energy Derivative Contracts, No Regulatory Recovery

TEP enters into certain contracts that qualify as derivatives, but do not meet the regulatory recovery criteria. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism.

Derivative Volumes

As of September 30, 2017, TEP had energy contracts that will settle on various expiration dates through 2020. The volumes associated with the energy contracts were as follows:



	September 30, 2017	December 31, 2016
Power Contracts GWh	3,840	2,610
Gas Contracts BBtu	29,261	12,355

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Level 3 Fair Value Measurements

The following tables provide 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, 2017
Forward Power Contracts	Market approach	$	5	$	(1	)	Market price per MWh	$	17.55	$	34.05



(in millions)	December 31, 2016
Forward Power Contracts	Market approach	$	2	$	(1	)	Market price per MWh	$	20.90	$	40.00

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:



	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2017			2016			2017			2016
Beginning of Period	$	4		$	3		$	1		$	(2	)
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	1			1			3			3
Wholesale Revenues	—			—			4			3
Settlements	(1		)	(1		)	(4		)	(1		)
End of Period	$	4		$	3		$	4		$	3

Gains (Losses), Assets (Liabilities) still held	$	—		$	—		$	4		$	3

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. TEP enters into contracts for the physical delivery of power and natural 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.

TEP has 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, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, a LOC, or other acceptable security to collateralize exposure beyond the allowed amounts.

TEP considers 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 allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.

The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $21 million as of September 30, 2017, compared with $8 million as of December 31, 2016. As of September 30, 2017, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on September 30, 2017, TEP would have been required to post an additional $21 million of collateral of which $14 million relates to outstanding net payable balances for settled positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. TEP uses the following methods and assumptions for estimating the fair value of 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, TEP uses quoted market prices, when available, or calculates the present value of the remaining cash flows at the balance sheet date. When calculating present value, the Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. The Company also incorporates the impact of its own credit risk using a credit default swap rate.

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



	Fair Value Hierarchy	Face Value				Fair Value
(in millions)	Fair Value Hierarchy	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,466	$	1,466	$	1,546	$	1,472

NOTE 10. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

TEP considers the applicability and impact of all Accounting Standard Updates (ASU) 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 either determined to not be applicable or are expected to have a minimal impact on TEP's condensed consolidated financial position, results of operations, or disclosures.

REVENUE FROM CONTRACTS WITH CUSTOMERS

In May 2014, the FASB issued an ASU intended to enable users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. Under the new standard, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. TEP does not expect the adoption of this new guidance to affect revenue recognition for tariff-based sales to retail and wholesale customers, which represent TEP's primary source of revenue. Accordingly, TEP does not expect the adoption of this standard to have a material effect on its financial statements. However, the presentation and disclosure requirements of the guidance will result in a change in the presentation of revenues on TEP's consolidated statements of income as well as expanded disclosures. The guidance is effective for annual and interim periods beginning January 1, 2018 and permits two implementation approaches: (i) retrospective application; or (ii) modified retrospective application by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings on the date of adoption supplemented by additional disclosures. TEP plans to adopt this standard on January 1, 2018, using the modified retrospective approach.

LEASES

In February 2016, the FASB issued an ASU 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.

RESTRICTED CASH

In November 2016, the FASB issued an ASU that will require entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents in the cash flow statement. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the cash flow statement. The standard is effective for annual and interim periods beginning January 1, 2018, and is to be applied using a retrospective approach. Early adoption is permitted. TEP expects to early adopt the new standard effective December 31, 2017. The adoption of the standard

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

will impact the presentation of the cash flow statement but will not have an impact on TEP's financial position or results of operations.

COMPENSATION—RETIREMENT BENEFITS

In March 2017, the FASB issued an ASU to improve the presentation of net periodic benefit cost for pension and other postretirement benefits. The guidance requires employers to retrospectively present the service cost component in the same line item as other compensation costs and to present the non-service cost components of net periodic benefit costs separately and outside a subtotal of operating income. The ASU is effective for annual and interim periods beginning January 1, 2018. Early adoption is permitted. TEP does not intend to early adopt the ASU and will implement the standard update in the first quarter of 2018. The Company does not expect that its adoption will have a material impact on its financial position or results of operations.

DERIVATIVES AND HEDGING

In August 2017, the FASB issued an ASU that enables entities to better align their risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance and the presentation of hedge results. The standard update expands an entity's ability to apply hedge accounting to nonfinancial and financial risk components and simplify fair value hedges of interest rate risk. The new guidance eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The amendments to the update also ease hedge documentation and effectiveness assessments requirements under previous guidance. The standard is effective for annual and interim periods beginning January 1, 2019. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures.

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

Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for TEP. It includes the following:


•	outlook and strategies;


•	operating results in the third quarter and first nine months of 2017 compared with the same periods in 2016;


•	factors affecting our results of operations and outlook;


•	liquidity and capital resources including contractual obligations, capital expenditures, 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 financial measures. It also includes non-GAAP financial measures which 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 2016 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 the following:


•	Achieving constructive outcomes in our regulatory proceedings that provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe and reliable service.

•

Continuing to focus on our long-term resource diversification 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, leveraging and improving our existing utility infrastructure, and maintaining financial strength. This long-term strategy includes a target of meeting 30% of our customers’ energy needs with non-carbon emitting resources by 2030.


•	Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.

2017 Operational and Financial Highlights

Management's Discussion and Analysis includes the following notable items:


•	In February 2017, the ACC issued a decision in TEP’s rate case approving a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and an equity ratio of approximately 50%. The new rates took effect on February 27, 2017.


•	In May 2017, the FERC informed TEP that no further enforcement actions were necessary as the investigation related to the FERC Refund Orders was closed. Previously, in January 2017 TEP and a counterparty, who had been a recipient

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of time-value refunds in compliance with the FERC Refund Orders, entered into a settlement agreement resulting in the counterparty paying TEP $8 million and TEP dismissing a previously filed appeal.


•	In June 2017, the Navajo Nation approved a land lease extension that allows Navajo to operate through December 2019 and decommissioning activities to begin thereafter. As a result of the planned early retirement, $52 million of Navajo’s NBV and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets.

•

In October 2017, TEP entered into a 20-year Tolling PPA with Salt River Project Agricultural Improvement and Power District (SRP) to purchase and receive all 550 MW of capacity, power, and ancillary services from Unit 2 of Gila River Generating Station (Gila River). The Tolling PPA will allow TEP to continue to move toward its long-term goal of resource diversification. TEP’s obligations under the agreement are contingent upon SRP's acquisition of Gila River Units 1 and 2, which is expected to be completed in the first quarter of 2018.

RESULTS OF OPERATIONS

The following discussion provides the significant items that affected TEP's results of operations in the third quarter and first nine months of 2017 compared with the same periods in 2016. The significant items affecting net income are presented on an after-tax basis.

The third quarter of 2017 compared with the third quarter of 2016

TEP reported net income of $82 million in the third quarter of 2017 compared with $72 million in the third quarter of 2016. The increase of $10 million, or 13.9%, was primarily due to:


•	$18 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order; and


•	$5 million in higher net income associated with late-filed TSAs. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

The increase was partially offset by:


•	$8 million in lower other revenues related to a September 2016 settlement involving Springerville Unit 1. For further information related to the settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q; and


•	$2 million in higher depreciation and amortization expenses.

The first nine months of 2017 compared with the first nine months of 2016

TEP reported net income of $164 million in the first nine months of 2017 compared with net income of $111 million in the first nine months of 2016. The increase of $53 million, or 47.7%, was primarily due to:


•	$40 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order and an increase in usage due to favorable weather;


•	$21 million in higher net income associated with late-filed TSAs. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q; and


•	$6 million in higher wholesale revenue primarily due to favorable pricing on wholesale contracts in 2017.

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The decrease was partially offset by:


•	$8 million in lower other revenues related to a September 2016 settlement involving Springerville Unit 1. For further information related to the settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q; and


•	$6 million in higher depreciation and amortization expenses.

Retail Sales and Revenues

The following tables provide a summary of retail kWh sales, a reconciliation of Retail Revenues from Retail Margin Revenues, and weather data for the third quarter of 2017 and 2016 and for the first nine months of 2017 and 2016, respectively.

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Retail Revenues were $340 million in the third quarter of 2017 compared with $320 million in the third quarter of 2016. Retail Margin Revenues (non-GAAP) were $234 million in the third quarter of 2017 compared with $207 million in the third quarter of 2016.



	Three Months Ended September 30,				Increase (Decrease)
	2017		2016		Amount			Percent
Retail Sales by Customer Class (kWh in millions)
Residential	1,361		1,344		17			1.3	%
Commercial	653		627		26			4.1	%
Industrial	559		590		(31		)	(5.3	)%
Mining	251		245		6			2.4	%
Public Authorities	3		6		(3		)	(50.0	)%
Total Retail Sales by Class	2,827		2,812		15			0.5	%
Retail Revenues (in millions)
Residential	$	119	$	101	$	18		17.8	%
Commercial	67		60		7			11.7	%
Industrial	31		30		1			3.3	%
Mining	11		10		1			10.0	%
Public Authorities	—		—		—			—	%
Retail Margin Revenues by Class	228		201		27			13.4	%
LFCR Revenues	6		5		1			20.0	%
Other Retail Margin Revenues	—		1		(1		)	(100.0	)%
Retail Margin Revenues (non-GAAP) ⁽¹⁾	234		207		27			13.0	%
Fuel and Purchased Power Revenues	92		98		(6		)	(6.1	)%
DSM and RES Surcharge Revenues	14		15		(1		)	(6.7	)%
Total Retail Revenues (GAAP)	$	340	$	320	$	20		6.3	%
Average Retail Margin Rate by Class (cents/kWh)
Residential	8.74		7.51		1.23			16.4	%
Commercial	10.26		9.57		0.69			7.2	%
Industrial	5.55		5.08		0.47			9.3	%
Mining	4.38		4.08		0.30			7.4	%
Public Authorities ⁽²⁾	8.28		5.76		2.52			43.8	%
Average Retail Margin Rate by Class	8.07		7.15		0.92			12.9	%
Total Average Retail Margin Rate ⁽³⁾	8.28		7.36		0.92			12.5	%
Average Fuel and Purchased Power Rate	3.25		3.49		(0.24		)	(6.9	)%
Average DSM and RES Surcharge Rate	0.50		0.53		(0.03		)	(5.7	)%
Total Average Retail Rate	12.03		11.38		0.65			5.7	%
Weather Data
Cooling Degree Days
Actual	1,006		962		44			4.6	%
10-year Average	1,018		1,018		*			*

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Retail Revenues were $820 million in the first nine months of 2017 compared with $781 million in the first nine months of 2016. Retail Margin Revenues (non-GAAP) were $561 million in the first nine months of 2017 compared with $500 million in the first nine months of 2016.



	Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Amount			Percent
Retail Sales by Customer Class (kWh in millions)
Residential	3,066		2,990		76			2.5	%
Commercial	1,671		1,633		38			2.3	%
Industrial	1,487		1,537		(50		)	(3.3	)%
Mining	745		743		2			0.3	%
Public Authorities	13		23		(10		)	(43.5	)%
Total Retail Sales by Class	6,982		6,926		56			0.8	%
Retail Revenues (in millions)
Residential	$	268	$	226	$	42		18.6	%
Commercial	162		146		16			11.0	%
Industrial	80		80		—			—	%
Mining	29		27		2			7.4	%
Public Authorities	1		1		—			—	%
Retail Margin Revenues by Class	540		480		60			12.5	%
LFCR Revenues	17		14		3			21.4	%
DSM Performance Bonus	2		2		—			—	%
Other Retail Margin Revenues	2		4		(2		)	(50.0	)%
Retail Margin Revenues (non-GAAP) ⁽¹⁾	561		500		61			12.2	%
Fuel and Purchased Power Revenues	219		243		(24		)	(9.9	)%
DSM and RES Surcharge Revenues	40		38		2			5.3	%
Total Retail Revenues (GAAP)	$	820	$	781	$	39		5.0	%
Average Retail Margin Rate by Class (cents/kWh)
Residential	8.74		7.56		1.18			15.6	%
Commercial	9.69		8.94		0.75			8.4	%
Industrial	5.38		5.20		0.18			3.5	%
Mining	3.89		3.63		0.26			7.2	%
Public Authorities ⁽²⁾	7.56		5.67		1.89			33.3	%
Average Retail Margin Rate by Class	7.73		6.93		0.80			11.5	%
Total Average Retail Margin Rate ⁽³⁾	8.03		7.22		0.81			11.2	%
Average Fuel and Purchased Power Rate	3.14		3.51		(0.37		)	(10.5	)%
Average DSM and RES Surcharge Rate	0.57		0.55		0.02			3.6	%
Total Average Retail Rate	11.74		11.28		0.46			4.1	%
Weather Data
Cooling Degree Days
Actual	1,592		1,431		161			11.3	%
10-year Average	1,502		1,491		*			*
Heating Degree Days
Actual	614		629		(15		)	(2.4	)%
10-year Average	739		773		*			*

* 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 revenues collected from retail customers that are directly

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offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between periods provides useful information for investors and analysts 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 Revenues, DSM Performance Bonus, and Other Retail Margin Revenues included in Retail Margin Revenues.

Retail Revenues increased in the third quarter and in the first nine months of 2017 when compared with the same periods in 2016 primarily due to higher retail margin revenues related to an increase in rates as approved in the 2017 Rate Order and an increase in usage due to favorable weather in the first and second quarters of 2017. The increases were partially offset by a decrease in Fuel and Purchased Power Revenues related to reduced recoveries due to lower PPFAC rates. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the PPFAC mechanism.

Wholesale Revenues



	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2017		2016			2017		2016
Long-Term Wholesale	$	11	$	6		$	30	$	23
Short-Term Wholesale	25		26			73		57
Transmission	8		9			22		23
Transmission Refunds ⁽¹⁾	—		(9		)	5		(22		)
Total Wholesale Revenues	$	44	$	32		$	130	$	81

⁽¹⁾

In 2016, FERC ordered TEP to make refunds associated with various late-filed TSAs for the time period during which rates were charged without FERC authorization. In May 2017, FERC informed TEP that no further enforcement actions were necessary as the related investigation was closed. 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 Refund Orders.

Wholesale Revenues increased by $12 million, or 37.5%, and $49 million, or 60.5%, in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The increases were primarily due to: (i) time-value FERC ordered refunds in 2016 and the reversal of accrued refunds in May 2017, both related to late-filed TSAs; (ii) favorable commodity pricing on the wholesale market; (iii) a wholesale contract that commenced January 2017; and (iv) an increase in Short-Term Wholesale volumes in the first quarter of 2017.

Short-Term Wholesale Revenues are primarily 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)	2017		2016		2017		2016
Springerville Units 3 and 4 ⁽¹⁾	$	23	$	21	$	61	$	59
Miscellaneous	10		21		26		35
Total Other Revenues	$	33	$	42	$	87	$	94


⁽¹⁾	Represents revenues and reimbursements to TEP from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, related to the operation of these generation facilities.

Other Revenues decreased by $9 million, or 21.4%, and $7 million, or 7.4%, in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The decreases were primarily related to a September 2016 settlement involving Springerville Unit 1. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further information related to the settlement.

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.

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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)	2017	2016	2017			2016
Coal-Fired Generation	2,212	2,369	$	56		$	53
Gas-Fired Generation	1,073	1,060	34			33
Utility Owned Renewable Generation	21	17	—			—
Reimbursed Fuel Expense, Springerville Units 3 and 4 ⁽¹⁾	—	—	2			1
Total Generation	3,306	3,446	92			87
Purchased Power, Non-Renewable	587	444	29			19
Purchased Power, Renewable	158	160	10			11
Total Purchased Power	745	604	39			30
Transmission and Other PPFAC Recoverable Costs	—	—	10			7
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—	—	(9		)	5
Total Generation and Purchased Power	4,051	4,050	$	132		$	129
Less Line Losses and Company Use	248	224
Total Power Sold	3,803	3,826



	Nine Months Ended September 30,
(in millions)	2017	2016	2017			2016
Coal-Fired Generation	5,764	5,958	$	138		$	139
Gas-Fired Generation	2,348	2,711	76			74
Utility Owned Renewable Generation	65	51	—			—
Reimbursed Fuel Expense, Springerville Units 3 and 4 ⁽¹⁾	—	—	4			4
Total Generation	8,177	8,720	218			217
Purchased Power, Non-Renewable	1,912	1,022	75			35
Purchased Power, Renewable	525	525	32			37
Total Purchased Power	2,437	1,547	107			72
Transmission and Other PPFAC Recoverable Costs	—	—	27			18
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—	—	(24		)	19
Total Generation and Purchased Power	10,614	10,267	$	328		$	326
Less Line Losses and Company Use	613	575
Total Power Sold	10,001	9,692


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

Fuel and Purchased Power Expense increased by $3 million, or 2.3%, and $2 million, or 0.6% in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The increases were primarily due to an increase in Purchased Power volumes used to compensate for the decrease in generation volumes and an increase in average fuel cost per kWh (see table below). The increases were partially offset by the reduction in recovery of the PPFAC costs as a result of changes in the PPFAC rates. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the PPFAC mechanism.

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The table below summarizes average fuel cost of generated and purchased power per kWh:



	Three Months Ended September 30,		Nine Months Ended September 30,
(cents per kWh)	2017	2016	2017	2016
Coal	2.54	2.23	2.40	2.34
Gas	3.16	3.07	3.23	2.73
Purchased Power, Non-Renewable	4.88	4.16	3.93	3.11
Purchased Power, Renewable	6.48	6.75	6.10	6.99
All Resources ⁽¹⁾	3.71	3.23	3.52	3.17


⁽¹⁾	Calculated on unrounded data and may not correspond exactly to data shown in Generation Output and Fuel and Purchased Power Expense table above.

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)	2017		2016		2017		2016
Reimbursed Expenses, Springerville Units 3 and 4 ⁽¹⁾	$	18	$	15	$	44	$	40
Reimbursed Expenses, Customer Funded Renewable Energy and DSM Programs ⁽²⁾	8		9		21		21
Other ⁽³⁾	64		65		191		199
Total Operations and Maintenance Expense	$	90	$	89	$	256	$	260


⁽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.


⁽³⁾	Includes the Third-Party Owners' share of expenses related to Springerville Unit 1 for the first nine months of 2016. See Note 6 for additional information regarding the Springerville Unit 1 settlement.

There were no significant changes to Operations and Maintenance Expense in the third quarter of 2017 compared with the same period in 2016.

Operations and Maintenance Expense decreased by $4 million, or 1.5%, in the first nine months of 2017 compared with the same period in 2016. The decrease was primarily due to a decrease in maintenance expense related to planned outages in the first quarter of 2016 and a sales tax refund in the second quarter of 2017.

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 2016 Annual Report on Form 10-K and new regulatory matters occurring in 2017.

2017 Rate Order

In February 2017, the ACC issued a rate order in the rate case filed by TEP in November 2015. TEP's rate filing was based on a test year ended June 30, 2015. The 2017 Rate Order approved new rates that went into effect on February 27, 2017.

The provisions of the 2017 Rate Order include, but are not limited to:


•	a non-fuel base rate increase of $81.5 million which includes $15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016;


•	a 7.04% return on original cost rate base of approximately $2 billion;


•	a cost of equity component of 9.75% and a cost of debt component of 4.32%;

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


•	adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and


•	approval of 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.

The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first quarter of 2018. See Phase 2 Proceedings below.

Distributed Generation

In 2016, the ACC held proceedings under the Value and Cost of Distributed Generation docket to examine the ACC’s net metering rules and determine the value that utilities should pay DG customers who deliver electricity from rooftop solar systems back to the grid. Prior to these proceedings, the ACC’s net metering rules allowed DG customers who over-produced electricity to carry-over or “bank” excess electricity at a value equal to the full retail rate per kWh. Banked kWh could then be used by customers to offset future energy usage that could not be met by their DG system.

In December 2016, the ACC approved an order that will begin to reform net metering in Arizona. The order adopts a number of net metering changes and policies, including:


•	placing DG customers in a separate rate class;


•	grandfathering current DG customers under net metering rules and rate design for 20 years from interconnection application;


•	eliminating the banking of excess kWh for non-grandfathered DG customers;


•	compensating non-grandfathered customers for their exported kWh for 10 years at the DG export rate in effect at the time of interconnection;


•	updating the DG export rate annually; and


•	developing an avoided cost methodology for calculating the DG export rate in the utility’s next rate case.

The initial DG export rate will be established in Phase 2. See Phase 2 Proceedings below.

Phase 2 Proceedings

In March 2017, TEP filed direct testimony in its Phase 2 proceedings addressing rate design for new DG customers. The proposals include options for either a Time-Of-Use (TOU) energy rate with a basic customer service charge plus a monthly grid access fee based on the size of the DG system; or a TOU energy rate with a basic customer service charge plus a charge based on the highest hourly demand during the month. Consistent with the ACC’s decision in the Value of DG docket proceedings, TEP also proposed that: (i) new DG customers receive a bill credit for excess energy exported to the grid at an initial rate of 9.7 cents/kWh; (ii) the DG export rate be updated based on a five-year rolling average cost of the company’s owned and contracted utility scale renewable energy projects; (iii) customers who submit DG applications prior to the ACC’s Phase 2 decision be grandfathered under current net metering rules and rate design for a period of 20 years from the date of interconnection of their DG system; and (iv) customers who install DG after the ACC’s Phase 2 decision be compensated for 10 years at the rate in effect at the time they file an application for interconnection. A final ACC decision is currently expected in the first quarter of 2018. TEP cannot predict the outcome of these proceedings.

Generating Resources

As of September 30, 2017, approximately 52% of TEP's peak generation capacity is sourced from coal-fired generation resources. As part of TEP's long-term diversification strategy, TEP is evaluating additional steps to reduce its reliance on coal-fired generation.

Integrated Resource Plan

TEP’s long-term strategy to shift to a more diverse, sustainable energy portfolio is described in its Integrated Resource Plan (IRP) filed in April 2017 with the ACC. TEP's 2017 IRP discusses continuing efforts to diversify its generation portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generating

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resources. TEP's existing coal generation fleet faces a number of uncertainties impacting the viability of continued operations including competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.

See Part I, Item 2. Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding the impact of environmental matters on generation facility operations.

Navajo Generating Station

In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. We are currently recovering Navajo capital and operating costs in base rates using a useful life through 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV, and other related costs, were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets in June 2017. We plan to seek recovery of all unrecovered costs in our next ACC rate case. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Sundt Generating Station

In August 2017, TEP submitted an Application to the PDEQ related to a generation modernization project at Sundt. In conjunction with the project, TEP will discontinue operation of Sundt Units 1 and 2 by the end of 2020. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets. We plan to seek recovery of all unrecovered costs in our next ACC rate case. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Under the project outlined in the Application, TEP will invest in 10 RICE generators scheduled for commercial operation between June 2019 through March 2020. The RICE generators are capable of quick starts and fast ramps to balance the variability of intermittent renewable energy resources and will add 190 MW of nominal net generating capacity. The RICE generation will replace the 162 MW of nominal net generating capacity from Sundt Units 1 and 2, which are less efficient than the RICE generators and do not have the same quick start, fast ramp capabilities.

Gila River Generating Station

In October 2017, TEP entered into a 20-year Tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2 (Tolling PPA). TEP’s obligations under the Tolling PPA are contingent upon SRP's acquisition of Gila River Units 1 and 2. In October 2017, SRP entered into a separate agreement with a third party to acquire Gila River Units 1 and 2 that is expected to be completed by early 2018 (Acquisition). If the Acquisition is terminated for any reason, either TEP or SRP may terminate the Tolling PPA without cost or penalty by providing written notice to the other party. The Tolling PPA provides TEP with an option to purchase Gila River Unit 2 during a three-year period beginning on the date the Acquisition is completed. TEP's purchase option price for Gila River Unit 2 is expected to be $165 million, but is dependent upon SRP's final purchase price. The Tolling PPA will replace coal-fired generation retirements and provide opportunities in the wholesale market for increased short-term wholesale revenues.

Long-Term Wholesale Sales

Navopache Electric Cooperative

In January 2017, a new long-term contract between TEP and Navopache Electric Cooperative (NEC) became effective. The contract expires at the end of 2041. TEP expects to serve 80% of NEC’s load requirements in 2017 and 100% beginning in 2018. In the nine months ended September 30, 2017, revenues from the NEC contract accounted for 8% of total Wholesale Revenues on the Condensed Consolidated Statements of Income.

Interest Rates

See Part II, Item 7A in our 2016 Annual Report on Form 10-K and Part II, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Cash flows may vary during the year with cash flows from operations typically the lowest in the first quarter of the year 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, 2017
Cash and Cash Equivalents	70
Amount Available under Revolving Credit Facility ⁽¹⁾	250
Total Liquidity	$	320


⁽¹⁾	TEP's revolving credit facility provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million with an original maturity date of October 2020. In October 2017, TEP requested and was granted its second one-year extension option. The facility's new maturity date is October 2022.

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 2016 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)	2017			2016			Percent
Operating Activities	337			341			(1.2	)%
Investing Activities	(254		)	(302		)	(15.9	)%
Financing Activities	(49		)	(38		)	28.9	%
Net Increase in Cash and Cash Equivalents	34			1			*
Cash and Cash Equivalents, Beginning of Period	36			56			(35.7	)%
Cash and Cash Equivalents, End of Period	$	70		$	57		22.8	%

* Not meaningful

Operating Activities

In the first nine months of 2017, net cash flows from operating activities decreased by $4 million compared with the same period in 2016. The decrease is primarily due to: (i) an ACC approved PPFAC credit that began returning the over-collected PPFAC balance to customers in February 2017; (ii) $12.5 million received in September 2016 related to a settlement for operating costs related to Springerville Unit 1 not occurring in 2017; and (iii) changes in working capital related to the timing of billing collections and payments. The decrease was partially offset by $8 million in cash proceeds received in January 2017 from a settlement agreement and higher net income due to an increase in: (i) rates as approved in the 2017 Rate Order; and (ii) residential usage due to favorable weather. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q, FERC Matters and Claims Related to Springerville Generating Station Unit 1, respectively, for additional information.

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Investing Activities

In the first nine months of 2017, net cash flows used for investing activities decreased by $48 million compared with the same period in 2016 primarily due to a $57 million decrease in cash paid for capital expenditures, highlighted by the September 2016 purchase of an undivided interest in Springerville Unit 1. The decrease was partially offset by an increase in renewable energy credits purchased in 2017.

Financing Activities

In the first nine months of 2017, net cash flows used for financing activities increased by $11 million compared with the same period in 2016 primarily due to an increase in the dividend paid to UNS Energy in 2017.

Sources of Liquidity

Short-Term Investments

Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of September 30, 2017, 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. As of September 30, 2017, there was $250 million available under the revolving credit commitments and LOC facility. As of November 2, 2017, TEP had $250 million available under its revolving credit commitments and LOC facility.

For details of TEP's credit facility see Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2016 Annual Report on Form 10-K.

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 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 2017. TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds issued in June 2008 by the Industrial Development Authority of Pima County, Arizona for the benefit of TEP and the bonds were not remarketed. The multi-modal bonds had an original maturity date of September 2029. In September 2017 the bonds were retired.

Depending on market conditions, TEP may refinance other debt issuances or make additional debt repurchases in the future.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. In April 2017, S&P Global Ratings upgraded TEP’s credit rating on senior unsecured debt to A- from BBB+, and as of September 30, 2017 the credit rating remained unchanged. As of September 30, 2017, Moody’s Investors Service credit ratings for TEP’s senior unsecured debt remained unchanged at A3.

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.

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Debt Covenants

Certain of TEP's debt agreements contain pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings, and the amount of fees it pays for its LOCs and unused commitments. Also, under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2017, TEP was in compliance with these covenants.

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.

Master Trading Agreements

TEP conducts its wholesale marketing and risk management activities under certain master agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, changes in TEP’s credit ratings, or material changes in TEP’s creditworthiness. As of September 30, 2017, TEP had posted no cash or LOCs as credit enhancements with its counterparties.

Contribution from Parent

TEP received no equity contributions in the three and nine months ended September 30, 2017 or 2016.

Dividends Paid to Parent

Capital Expenditures

TEP's capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. Our capital expenditures in the first nine months of 2017 were $216 million compared to $273 million for the same period in 2016. TEP's forecasted capital expenditures are summarized below:



(in millions)	2017		2018		2019		2020		2021
Generation Facilities:
Environmental Compliance	$	23	$	11	$	1	$	2	$	—
Renewable Energy	6		15		21		26		26
Springerville Common Lease Purchase	38		—		—		—		9
Replacement Generation Capacity⁽¹⁾	13		132		190		53		29
Other Generation Facilities	41		80		35		76		63
Total Generation Facilities	121		238		247		157		127
Transmission and Distribution	167		176		161		169		162
General and Other ⁽²⁾	76		76		106		53		39
Total Capital Expenditures	$	364	$	490	$	514	$	379	$	328


⁽¹⁾	Investments that will provide replacement capacity for the planned early retirements of generating resources which include: (i) RICE generators at Sundt; and (ii) the purchase option price for Gila River Unit 2. See Part I, Item 2. Factors Affecting Results, Generating Resources of this Form 10-Q for additional information on these projects.


⁽²⁾	Includes cost for information technology, fleet, facilities, and communication equipment.

These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, construction schedules, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt or other borrowings.

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Contractual Obligations

In the first nine months of 2017, there have been no material changes outside the ordinary course of business to contractual obligations as reported in our 2016 Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2016 Annual Report on Form 10-K, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.

Income Tax Position

Prior year tax legislation includes provisions that make qualified property placed in service between 2010 and 2019 eligible for bonus depreciation for tax purposes. In addition, the IRS issued 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 2017 and does not expect to make any payments until 2020.

Environmental Matters

The Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon dioxide (CO₂), particulate matter, mercury and other by-products produced by generation facilities. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance through Retail Rates.

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The 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 generation facilities.

In the western United States, Regional Haze BART determinations have focused on controls for NO_x, often resulting in a requirement to install Selective Catalytic Reduction (SCR). 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 2021. In December 2016, the EPA signed a final rule, entitled "Protection of Visibility: Amendments to Requirements for State Plans." Among other things, the rule changes the date for submittal of the next regional haze implementation plan from 2018 to 2021. Based on recent Regional Haze requirement time-frames, TEP anticipates that impacts, if any, to Springerville will likely occur three to five years after the 2021 plan submittal date. TEP cannot predict the ultimate outcome of these matters.

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 install SCR on Units 4 and 5. TEP owns 7% of Four Corners Units 4 and 5. TEP's estimated share of NO_x emissions control costs to comply with the rules is $44 million in capital expenditures and $2 million in annual operations and maintenance expenses. The SCR projects are scheduled to be completed by July 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 facility. The facility has until December 2019 to notify the EPA of how it will comply with the FIP.

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In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. As a result of the early retirement of Navajo, TEP and the co-owners will no longer be responsible for implementing the FIP. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the early retirement of Navajo.

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 the end of December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4. TEP owns 50% of Units 1 and 2 at San Juan. Public Service Company of New Mexico (PNM), the operator of San Juan, completed the installation of SNCR in February 2016. PNM obtained New Mexico Public Regulation Commission approval to shut down Units 2 and 3 at San Juan.

In anticipation of the retirement of San Juan Unit 2 in December 2017, TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the retirement of San Juan Unit 2.

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. TEP applied excess depreciation reserves against the unrecovered NBV of the coal handling facilities at Sundt as approved in the 2017 Rate Order. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the retirement of the coal handling facilities at Sundt.

Greenhouse Gas Regulation

In August 2015, the EPA issued the CPP limiting CO₂ emissions from existing and new fossil fueled generation facilities. The Clean Power Plan (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 generation facilities 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 compliance with the Regional Haze Rules will be equivalent to those required under the CPP rule.

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.

In September 2016, the U.S. Court of Appeals for the District of Columbia Circuit (U.S. Court of Appeals) heard oral arguments on the CPP. On March 28, 2017, the Department of Justice filed a motion to hold the lawsuits related to the CPP in abeyance. On April 28, 2017, the U.S. Court of Appeals granted that motion and delayed for 60 days the litigation over the EPA's CPP for existing and new generation facilities. The EPA has asked for an extension.

In March 2017, a Presidential Executive Order (EO) titled "Promoting Energy Independence and Economic Growth" was issued. The EO instructs the EPA to review the final greenhouse gas rule for existing and new and modified generation facilities and either suspend, revise, or rescind the rule as appropriate. In April 2017, the EPA announced in the Federal Register that it is reviewing and, if appropriate, will initiate proceedings to suspend, revise, or rescind the CPP rule.

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In October 2017, the EPA signed a proposal to repeal the CPP that was promulgated on October 23, 2015. Specifically, the EPA proposes a change in the legal interpretation as applied to section 111(d) of the Clean Air Act (CAA) on which the CPP was based. Comments to this proposal will be accepted for 60 days following publication in the Federal Register.

The EPA has not determined whether or not it will issue a potential replacement rule and, if it will do so, under what form. The EPA intends to issue an Advance Notice of Proposed Rulemaking (ANPRM) in the near future to seek comment on what, if any, regulation should replace the existing CPP. In light of recent events TEP cannot predict the final 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 (RCRA Subtitle D) 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 costs at Springerville is estimated to be $2 million, the majority of which is expected to be capital expenditures. TEP currently estimates its share of 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.

In December 2016, Congress approved the Water Infrastructure Improvements for the Nation Act which authorizes the States to establish permit programs under RCRA Subtitle D for implementing regulation for Coal Combustion Residuals (CCR). TEP is currently working with other affected utilities and the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.

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 apply accounting policies and make estimates, judgments, and assumptions that affect the reported amounts of assets, liabilities, net revenues and expenses, and disclosure of contingent liabilities. Management believes that there have been no significant changes during the nine months ended September 30, 2017, 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 2016 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 2016 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

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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 SEC’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, 2017.

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 quarter ended September 30, 2017, 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 Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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 2016 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 2016 Form 10-K.

ITEM 5. OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES



	Nine Months Ended	Twelve Months Ended
	September 30, 2017	September 30, 2017
Ratio of Earnings to Fixed Charges	5.74	4.89

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.

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ITEM 6. EXHIBITS



EXHIBIT INDEX
Exhibit No.		Description
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 Frank P. Marino

*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.

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 3, 2017	/s/ Frank P. Marino
		Frank P. Marino
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

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