Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2019

☐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		86-0062700
(State or other jurisdiction of incorporation or organization)		(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

Securities registered pursuant to Section 12(b) of the Act: None

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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.

Large Accelerated Filer ☐ Accelerated Filer ☐ Non-Accelerated Filer ☒ Smaller Reporting Company ☐ Emerging Growth Company ☐

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

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 August 1, 2019.

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	34
New Accounting Standards Issued and Not Yet Adopted	34
Item 3. Quantitative and Qualitative Disclosures about Market Risk	34
Item 4. Controls and Procedures	34

PART II

Item 1. Legal Proceedings	35
Item 1A. Risk Factors	35
Item 6. Exhibits	36
Signatures	37

DEFINITIONS

The abbreviations and acronyms used in this Form 10-Q are defined below:

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS



2019 Rate Case		A pending general rate case filed with the ACC by TEP in April 2019 requesting new rates be implemented in May 2020
ACC		Arizona Corporation Commission
ACC Refund Order		An order issued by the ACC approving TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability that reflects the deferral of the return of a portion of the savings, effective May 1, 2018
AFUDC		Allowance for Funds Used During Construction
AMT		Alternative Minimum Tax
CAISO		California Independent System Operator
DG		Distributed Generation
DSM		Demand Side Management
EDIT		Excess Deferred Income Taxes
EE Standards		Energy Efficiency Standards
EIM		Energy Imbalance Market
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Generally Accepted Accounting Principles in the United States of America
LFCR		Lost Fixed Cost Recovery
LOC		Letter(s) of Credit
OATT		Open Access Transmission Tariff
PPA		Power Purchase Agreement
PPFAC		Purchased Power and Fuel Adjustment Clause
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
SEC		Securities and Exchange Commission
TCA		Transmission Cost Adjustor
TCJA		Tax Cuts and Jobs Act
TEAM		Tax Expense Adjustor Mechanism
Tolling PPA		A 20-year tolling PPA that TEP entered into in 2017 with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which includes a three-year option to purchase the unit
VIE		Variable Interest Entity

ENTITIES AND GENERATING STATIONS



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
Gila River		Gila River Generating Station
Luna		Luna Generating Station
Navajo		Navajo Generating Station
San Juan		San Juan Generating Station

iii



SES		Southwest Energy Solutions, Inc.
Springerville		Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sundt		H. Wilson Sundt Generating Station
TEP		Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Tri-State		Tri-State Generation and Transmission Association, Inc.
UNS Electric		UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy		UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates		Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas		UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation

UNITS OF MEASURE



BBtu		Billion British thermal unit(s)
GWh		Gigawatt-hour(s)
kWh		Kilowatt-hour(s)
MW		Megawatt(s)
MWh		Megawatt-hour(s)

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. 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 economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, believes, estimates, expects, intends, may, plans, predicts, 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 2018 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: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax and energy policies; changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output or accelerate generation facility retirements; the outcome of the general rate case filed with the ACC in April 2019; the outcome of the proposal filed with the FERC in May 2019 requesting revisions to TEP's OATT; regional economic and market conditions that could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; our forecasts of peak demand and whether existing generation capacity and PPA are sufficient to meet the expected demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital; 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 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; the performance of TEP's generation facilities; the development of our wind-powered electric generation facility in southeastern New Mexico; and the impact of the TCJA on our financial condition and results of operations, including the assumptions we make relating thereto.

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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Operating Revenues	$	326,091		$	354,246		$	659,094		$	629,336

Operating Expenses
Fuel	75,441			62,870			164,859			130,893
Purchased Power	27,345			32,389			60,195			52,753
Transmission and Other PPFAC Recoverable Costs	12,094			9,909			24,019			19,700
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(10,918		)	13,372			(4,713		)	5,406
Total Fuel and Purchased Power	103,962			118,540			244,360			208,752
Operations and Maintenance	92,045			93,445			178,633			176,601
Depreciation	41,427			39,418			82,744			78,294
Amortization	7,397			6,021			15,014			12,042
Taxes Other Than Income Taxes	14,120			14,299			28,321			28,479
Total Operating Expenses	258,951			271,723			549,072			504,168

Operating Income	67,140			82,523			110,022			125,168

Other Income (Expense)
Interest Expense	(22,144		)	(16,707		)	(44,275		)	(33,192		)
Allowance For Borrowed Funds	1,303			706			2,577			1,393
Allowance For Equity Funds	3,398			1,532			6,721			3,177
Other, Net	842			1,679			4,130			1,255
Total Other Income (Expense)	(16,601		)	(12,790		)	(30,847		)	(27,367		)

Income Before Income Tax Expense	50,539			69,733			79,175			97,801
Income Tax Expense	8,476			12,136			10,917			16,401
Net Income	$	42,063		$	57,597		$	68,258		$	81,400

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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Comprehensive Income
Net Income	$	42,063	$	57,597	$	68,258	$	81,400
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $8 and $32	24		96
Net of Income Tax Expense of $17 and $73					52		219
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $22 and $39	66		117
Net of Income Tax Expense of $44 and $79					132		232
Total Other Comprehensive Income, Net of Tax	90		213		184		451
Total Comprehensive Income	$	42,153	$	57,810	$	68,442	$	81,851

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)



	Six Months Ended June 30,
	2019			2018
Cash Flows from Operating Activities
Net Income	$	68,258		$	81,400
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	82,744			78,294
Amortization Expense	15,014			12,042
Amortization of Debt Issuance Costs	1,153			1,168
Use of Renewable Energy Credits for Compliance	18,624			15,132
Deferred Income Taxes	14,244			21,924
Pension and Other Postretirement Benefits Expense	8,881			7,668
Pension and Other Postretirement Benefits Funding	(6,431		)	(5,708		)
Allowance for Equity Funds Used During Construction	(6,721		)	(3,177		)
Regulatory Deferral, ACC Refund Order	3,156			—
Changes in Current Assets and Current Liabilities:
Accounts Receivable	5,910			(41,534		)
Materials, Supplies, and Fuel Inventory	(4,689		)	8,102
Regulatory Assets	(151		)	(5,008		)
Other Current Assets	1,766			(1,677		)
Accounts Payable and Accrued Charges	(32,061		)	16,385
Income Taxes Receivable	(3,326		)	(5,521		)
Regulatory Liabilities	(4,507		)	17,180
Other, Net	969			1,117
Net Cash Flows—Operating Activities	162,833			197,787
Cash Flows from Investing Activities
Capital Expenditures	(199,791		)	(174,810		)
Purchase Intangibles, Renewable Energy Credits	(24,793		)	(25,848		)
Contributions in Aid of Construction	3,932			7,773
Net Cash Flows—Investing Activities	(220,652		)	(192,885		)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	—			66,000
Repayments of Borrowings, Revolving Credit Facility	—			(93,000		)
Payments of Finance Lease Obligations	(10,889		)	(10,930		)
Other, Net	(166		)	(3		)
Net Cash Flows—Financing Activities	(11,055		)	(37,933		)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash	(68,874		)	(33,031		)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	152,747			49,501
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	83,873		$	16,470

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)



	June 30, 2019			December 31, 2018
ASSETS
Utility Plant
Plant in Service	$	6,126,496		$	6,020,469
Utility Plant Under Finance Leases	248,635			248,635
Construction Work in Progress	298,115			258,965
Total Utility Plant	6,673,246			6,528,069
Accumulated Depreciation and Amortization	(2,337,169		)	(2,293,783		)
Accumulated Amortization of Finance Lease Assets	(79,829		)	(73,646		)
Total Utility Plant, Net	4,256,248			4,160,640

Investments and Other Property	55,479			50,952

Current Assets
Cash and Cash Equivalents	69,692			138,114
Accounts Receivable, Net	159,165			172,367
Fuel Inventory	26,131			22,783
Materials and Supplies	109,331			107,990
Regulatory Assets	118,699			106,725
Derivative Instruments	7,216			3,929
Other	27,131			25,571
Total Current Assets	517,365			577,479
Regulatory and Other Assets
Regulatory Assets	292,068			293,078
Derivative Instruments	11,428			8,402
Other	85,351			68,656
Total Regulatory and Other Assets	388,847			370,136
Total Assets	$	5,217,939		$	5,159,207

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)



	June 30, 2019			December 31, 2018
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 June 30, 2019 and December 31, 2018)	$	1,346,539		$	1,346,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	552,535			484,277
Accumulated Other Comprehensive Loss	(4,530		)	(4,714		)
Total Common Stock Equity	1,888,187			1,819,745
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2019 and December 31, 2018)	—			—
Finance Lease Obligations	6,192			19,773
Long-Term Debt, Net	1,616,205			1,615,252
Total Capitalization	3,510,584			3,454,770
Current Liabilities
Finance Lease Obligations	175,202			172,510
Accounts Payable	105,712			133,012
Accrued Taxes Other than Income Taxes	40,499			41,686
Accrued Employee Expenses	25,393			34,339
Accrued Interest	17,548			17,927
Regulatory Liabilities	89,898			95,094
Customer Deposits	25,191			27,650
Derivative Instruments	31,242			18,137
Other	24,204			21,555
Total Current Liabilities	534,889			561,910
Regulatory and Other Liabilities
Deferred Income Taxes, Net	390,831			369,705
Regulatory Liabilities	497,572			512,425
Pension and Other Postretirement Benefits	116,306			117,472
Derivative Instruments	29,868			19,361
Other	137,889			123,564
Total Regulatory and Other Liabilities	1,172,466			1,142,527

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	5,217,939		$	5,159,207

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

(Concluded)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in thousands)



	Three Months Ended
	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances as of March 31, 2018	$	1,296,539	$	(6,357	)	$	404,757	$	(6,866	)	$	1,688,073
Net Income						57,597					57,597
Other Comprehensive Income, Net of Tax								213			213
Balances as of June 30, 2018	$	1,296,539	$	(6,357	)	$	462,354	$	(6,653	)	$	1,745,883



Balances as of March 31, 2019	$	1,346,539	$	(6,357	)	$	510,472	$	(4,620	)	$	1,846,034
Net Income						42,063					42,063
Other Comprehensive Income, Net of Tax								90			90
Balances as of June 30, 2019	$	1,346,539	$	(6,357	)	$	552,535	$	(4,530	)	$	1,888,187



	Six Months Ended
	Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances as of December 31, 2017	$	1,296,539	$	(6,357	)	$	380,076	$	(6,226	)	$	1,664,032
Net Income						81,400					81,400
Other Comprehensive Income, Net of Tax								451			451
Adoption of ASU, Cumulative Effect Adjustment						878		(878		)	—
Balances as of June 30, 2018	$	1,296,539	$	(6,357	)	$	462,354	$	(6,653	)	$	1,745,883



Balances as of December 31, 2018	$	1,346,539	$	(6,357	)	$	484,277	$	(4,714	)	$	1,819,745
Net Income						68,258					68,258
Other Comprehensive Income, Net of Tax								184			184
Balances as of June 30, 2019	$	1,346,539	$	(6,357	)	$	552,535	$	(4,530	)	$	1,888,187

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

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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 427,000 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, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC's 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 records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities 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 2018 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 statement 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 VIE, and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it 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 PPAs 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 of these VIEs 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 June 30, 2019, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. 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 cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

Restricted Cash

Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:



	Six Months Ended June 30,
(in millions)	2019		2018
Cash and Cash Equivalents	$	70	$	6
Restricted Cash included in:
Investments and Other Property	13		9
Current Assets—Other	1		1
Total Cash, Cash Equivalents, and Restricted Cash	$	84	$	16

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

Leases

TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 6 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

NOTE 2. REGULATORY MATTERS

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

2019 ACC RATE CASE

On April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018. The filing requests new rates be implemented by May 1, 2020.

The key proposals of the rate case include:


•	a non-fuel retail revenue increase of $115 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76 million, or 7.8%, over test year retail revenues;


•	a 7.68% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.35% and an average cost of debt of 4.65%;


•	a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the planned purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

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•	a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and


•	a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

TEP cannot predict the outcome of the proceeding.

2019 FERC RATE CASE

On May 31, 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing requests that the proposed revisions be implemented by August 1, 2019.

The key proposals of the filing include:


•	replacing TEP's stated transmission rates with a forward-looking formula rate;


•	a 10.4% return on equity; and


•	elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.

The requested forward-looking formula rate will allow for more timely recovery of transmission related costs.

On July 31, 2019, FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures. TEP cannot predict the outcome of the proceeding.

Abandoned Plant Costs

Also on May 31, 2019, TEP filed with the FERC a request to recover through its OATT rates abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. TEP cannot predict the outcome of this proceeding. As of June 30, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Condensed Consolidated Balance Sheets.

FEDERAL TAX LEGISLATION

Arizona Corporation Commission

In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The 2018 refund amount totaled $33 million. TEP filed an information filing with the ACC to establish a 2019 customer refund of $34 million.

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Beginning of Period	$	3		$	(7	)	$	4		$	—
ACC Refund (Reduction in Operating Revenues)	(9		)	(10		)	(16		)	(17		)
Amount Returned to Customers through Bill Credits	6			12			10			12
Regulatory Deferral	1			—			3			—
End of Period	$	1		$	(5	)	$	1		$	(5	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

COST RECOVERY MECHANISMS

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

Purchased Power and Fuel Adjustment Clause

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

The table below summarizes the PPFAC regulatory asset (liability) balance:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Beginning of Period	$	(22	)	$	(4	)	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs ⁽¹⁾	6			(11		)	3			(9		)
PPFAC Refunds (Recoveries) ⁽²⁾	7			(3		)	5			—
End of Period	$	(9	)	$	(18	)	$	(9	)	$	(18	)


⁽¹⁾	The negative balance in Deferred Fuel and Purchased Power Costs represents a decrease in the actual cost of fuel and purchased power below the costs associated with base recoveries.


⁽²⁾	The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement is 9% of retail electric sales in 2019 and increases annually until renewable retail sales represent at least 15% by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC.

In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million, which is recovered through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 2019 and 2018 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.

In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is collected through the DSM surcharge.

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 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income:



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
LFCR Revenues	$	6	$	5	$	16	$	13

REGULATORY ASSETS AND LIABILITIES

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



($ in millions)	Remaining Recovery Period (years)	June 30, 2019		December 31, 2018
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	123	$	126
Early Generation Retirement Costs ⁽¹⁾	Various	67		72
Derivatives (Note 9)	11	47		27
Income Taxes Recoverable through Future Rates ⁽²⁾	Various	44		47
Lost Fixed Cost Recovery	2	42		35
Final Mine Reclamation and Retiree Healthcare Costs ⁽³⁾	19	26		29
Property Tax Deferrals ⁽⁴⁾	1	24		23
Springerville Unit 1 Leasehold Improvements⁽⁵⁾	4	10		11
Other Regulatory Assets	Various	28		30
Total Regulatory Assets		411		400
Less Current Portion	1	119		107
Total Non-Current Regulatory Assets		$	292	$	293



Regulatory Liabilities
Income Taxes Payable through Future Rates ⁽²⁾	Various	$	344	$	354
Net Cost of Removal ⁽⁶⁾	Various	162		171
Renewable Energy Standard	Various	53		52
Purchased Power and Fuel Adjustment Clause	1	9		17
Deferred Investment Tax Credits ⁽⁷⁾	Various	7		7
Other Regulatory Liabilities	Various	13		6
Total Regulatory Liabilities		588		607
Less Current Portion	1	90		95
Total Non-Current Regulatory Liabilities		$	498	$	512

⁽¹⁾

Includes the net book value 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. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10-year period in the 2019 Rate Case.


⁽²⁾	Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA.


⁽³⁾	Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038.

⁽⁴⁾

Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)


⁽⁵⁾	Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.


⁽⁶⁾	Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant, which are not yet expended.


⁽⁷⁾	Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

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 and Income Taxes Payable through Future Rates related to the EDIT balances, TEP does not pay a return on regulatory liabilities.

NOTE 3. REVENUE

DISAGGREGATION OF REVENUES

TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Retail	$	236	$	273	$	438	$	465
Wholesale	43		35		127		73
Other Services	30		27		54		50
Revenues from Contracts with Customers	309		335		619		588
Alternative Revenues	6		5		18		15
Other	11		14		22		26
Total Operating Revenues	$	326	$	354	$	659	$	629

NOTE 4. ACCOUNTS RECEIVABLE

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



(in millions)	June 30, 2019			December 31, 2018
Customer⁽¹⁾	$	85		$	99
Customer, Unbilled	59			45
Due from Affiliates (Note 5)	6			8
Other	14			25
Allowance for Doubtful Accounts	(5		)	(5		)
Accounts Receivable, Net	$	159		$	172


⁽¹⁾	Includes $3 million as of June 30, 2019, and $8 million as of December 31, 2018, of receivables related to revenue from derivative instruments.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and the UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor related services.

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



(in millions)	June 30, 2019		December 31, 2018
Receivables from Related Parties
UNS Electric	$	4	$	7
UNS Gas	2		1
Total Due from Related Parties	$	6	$	8

Payables to Related Parties
SES	$	2	$	2
UNS Energy	2		1
UNS Electric	—		1
UNS Gas	—		1
Total Due to Related Parties	$	4	$	5

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



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric ⁽¹⁾	$	2	$	1	$	3	$	3
Control Area Services, UNS Electric ⁽²⁾	1		1		2		1
Common Costs, UNS Energy Affiliates ⁽³⁾	5		5		10		9

Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES ⁽⁴⁾	4		4		7		7
Corporate Services, UNS Energy ⁽⁵⁾	2		1		3		3
Corporate Services, UNS Energy Affiliates ⁽⁶⁾	1		1		2		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 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 83% 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 six months ended June 30, 2019 and 2018, respectively.


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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DIVIDENDS PAID TO PARENT

On July 22, 2019, TEP declared a $38 million dividend to UNS Energy which was paid July 30, 2019.

NOTE 6. LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.

TEP leases generation facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s leases are included on the balance sheet as follows:



(in millions)	Lease Type	June 30, 2019
Lease Assets
Utility Plant Under Finance Leases	Finance	$	249
Accumulated Amortization of Finance Lease Assets	Finance	(80		)
Regulatory and Other Assets, Other	Operating	8
Lease Liabilities
Current Liabilities, Finance Lease Obligations ⁽¹⁾⁽²⁾	Finance	175
Finance Lease Obligations⁽²⁾	Finance	6
Current Liabilities, Other	Operating	1
Regulatory and Other Liabilities, Other	Operating	7


⁽¹⁾	TEP recorded the fair value purchase price of Gila River Unit 2 as determined by SRP's 2018 purchase price. TEP expects to complete the purchase of Gila River Unit 2 in December 2019.


⁽²⁾	Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options.

The following table presents the components of TEP’s lease cost:



	Three Months Ended		Six Months Ended
(in millions)	June 30, 2019
Finance
Amortization of Leased Assets	$	3	$	6
Interest on Lease Liabilities ⁽¹⁾	3		6
Operating	—		1
Variable	5		9
Total Lease Cost	$	11	$	22


⁽¹⁾	Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.

TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of June 30, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:



(in millions)	Finance Leases ⁽¹⁾		Operating Leases		Total
2019	$	170	$	1	$	171
2020	20		1		21
2021	—		1		1
2022	—		1		1
2023	—		1		1
Thereafter	—		5		5
Total Lease Payments	190		10		200
Less Imputed Interest	9		2		11
Total Lease Obligations	181		8		189
Less Current Portion	175		1		176
Total Non-Current Lease Obligations	$	6	$	7	$	13


⁽¹⁾	Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.

The following table presents TEP's lease terms and discount rate related to its leases:



	June 30, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	7.1	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:



	Six Months Ended
(in millions)	June 30, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	7
Financing Cash Flows used for Finance Leases	11
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities
Operating Leases	8

Operating cash flows from operating leases for the six months ended June 30, 2019, were not material.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to five years. Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years.

Operating lease income for the three and six months ended June 30, 2019, was not material to TEP's results of operations. TEP's expected operating lease payments to be received as of June 30, 2019, are $1 million in each of 2019 through 2023 and thereafter.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:



(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

Operating lease cost for the three and six months ended June 30, 2018, was not material to TEP's results of operations.

The following table presents TEP's non-cash investing information related to its leases:



	Six Months Ended
(in millions)	June 30, 2018
Assets Obtained in Exchange for New Lease Liabilities
Capital Leases	$	165

In May 2018, TEP recorded an increase to both capital lease assets and liabilities related to the 20-year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA includes a three-year option to purchase the unit. The amount reflects the fair value of the unit as determined by SRP's purchase price.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

In addition to those reported in its 2018 Annual Report on Form 10-K, TEP entered into the following long-term commitment:

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 operations or 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 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 Office of Surface Mining Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to San Juan Coal

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Company (SJCC)) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, including: (i) failure to provide requisite public notice and participation, and (ii) 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 OSMRE so the OSMRE 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 provides that: (i) the OSMRE's decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. In May 2018, the OSMRE released a draft EIS for public comment which was open through July 2018. On April 30, 2019, the OSMRE issued a final Record of Decision (ROD) on the Final EIS released March 15, 2019. The Final EIS contemplates continued mining at the San Juan Mine in annual quantities similar to those currently being provided through 2033. TEP plans to retire San Juan in 2022. The OSMRE's ROD is subject to approval by the Assistant Secretary for Land and Minerals Management. TEP cannot currently predict the outcome of this matter.

Mine Reclamation at Generation 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 estimated share of mine reclamation costs at all three mines is $63 million. Payments will be made through the expiration of the coal supply agreements, which expire between December 2019 and 2031. An aggregate liability balance related to final mine reclamation of $36 million as of June 30, 2019 and December 31, 2018, was reflected in current and non-current Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

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 out.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and 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 June 30, 2019, there have been no such payment defaults under any of the participation agreements. The participation agreements expire in: (i) December 2019 at Navajo; (ii) 2022 at San Juan; (iii) 2041 at Four Corners; and (iv) 2046 at Luna.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2019			2018			2019		2018
Service Cost	$	3		$	3		$	1	$	1
Non-Service Cost ⁽¹⁾
Interest Cost	5			4			1		1
Expected Return on Plan Assets	(7		)	(7		)	—		—
Amortization of Net Loss	2			2			—		—
Net Periodic Benefit Cost	$	3		$	2		$	2	$	2



	Six Months Ended June 30,
(in millions)	2019			2018			2019		2018
Service Cost	$	6		$	7		$	2	$	2
Non-Service Cost⁽¹⁾
Interest Cost	9			8			1		1
Expected Return on Plan Assets	(13		)	(14		)	—		—
Amortization of Net Loss	4			4			—		—
Net Periodic Benefit Cost	$	6		$	5		$	3	$	3


⁽¹⁾	The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

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.

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 classified in their entirety based on the lowest level of input that is significant to the fair value measurement:



	Level 1		Level 2			Level 3			Total
(in millions)	June 30, 2019
Assets
Cash Equivalents ⁽¹⁾	$	67	$	—		$	—		$	67
Restricted Cash ⁽¹⁾	14		—			—			14
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		10			3			13
Energy Derivative Contracts, No Regulatory Recovery ⁽²⁾	—		—			6			6
Total Assets	81		10			9			100
Liabilities
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		(48		)	(13		)	(61		)
Total Liabilities	—		(48		)	(13		)	(61		)
Total Assets (Liabilities), Net	$	81	$	(38	)	$	(4	)	$	39

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



(in millions)	December 31, 2018
Assets
Cash Equivalents ⁽¹⁾	$	125	$	—		$	—		$	125
Restricted Cash ⁽¹⁾	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery ⁽²⁾	—		—			2			2
Total Assets	140		10			2			152
Liabilities
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	140	$	(25	)	$	—		$	115

⁽¹⁾

Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts 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. In 2019, Derivative Contract Liabilities increased primarily due to increases in volume and decreases in forward market prices of natural gas.

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)	June 30, 2019
Derivative Assets
Energy Derivative Contracts	$	19		$	13		$	—	$	6
Derivative Liabilities
Energy Derivative Contracts	(61		)	(13		)	—		(48		)



(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

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. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.

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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense are not material to TEP's financial position or results of operations.

As of June 30, 2019, the total notional amount of the interest rate swap was $6 million.

Energy Derivative Contracts, Regulatory Recovery

TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Unrealized Net Gain (Loss)	$	(11	)	$	(14	)	$	(20	)	$	(32	)

Energy Derivative Contracts, No Regulatory Recovery

TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. 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. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income:



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Operating Revenues	$	5	$	4	$	5	$	5

Derivative Volumes

As of June 30, 2019, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:



	June 30, 2019	December 31, 2018
Power Contracts GWh	5,836	1,743
Gas Contracts BBtu	138,837	146,933

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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

Unobservable Inputs

Range of Unobservable Inputs

Assets

Liabilities

(in millions)

June 30, 2019

Forward Power Contracts

Market approach

(13

)

Market price per MWh

17.05

64.60



(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

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 June 30,					Six Months Ended June 30,
(in millions)	2019			2018		2019			2018
Beginning of Period	$	(6	)	$	1	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(2		)	—		(10		)	—
Operating Revenues	5			4		5			4
Settlements	(1		)	—		—			(1		)
End of Period	$	(4	)	$	5	$	(4	)	$	5

Gains (Losses), Assets (Liabilities) Still Held	$	3		$	6	$	(4	)	$	5

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 measurements 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, LOCs, 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 $84 million as of June 30, 2019, compared with $41 million as of December 31, 2018. As of June 30, 2019, TEP had no collateral posted with its counterparties. If the credit risk contingent features were triggered on June 30, 2019, TEP would have been required to post an additional $84 million of collateral of which $15 million relates to outstanding net payable balances for settled positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

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. 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.

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	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,629	$	1,629	$	1,745	$	1,672

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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 financial condition, and the outlook for TEP. It includes the following:


•	outlook and strategies;


•	results of operations in the second quarter and first six months of 2019 compared with the same periods in 2018;


•	factors affecting results of operations;


•	liquidity and capital resources including: (i) capital expenditures; (ii) contractual obligations; and (iii) environmental matters;


•	critical accounting policies and estimates; and


•	new accounting standards issued and not yet adopted.

Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP financial measures.

Management’s Discussion and Analysis should be read in conjunction with the 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 future results to differ from those we currently expect or anticipate, see Forward-Looking Information at the front of this Form 10-Q and Risk Factors in Part 1, Item 1A of our 2018 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.

References in this discussion and analysis 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 and legislative actions. Our plans and strategies include:


•	Achieving constructive outcomes in our regulatory proceedings that will 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 transitioning from carbon-intensive sources to a more sustainable energy portfolio, 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. This resource strategy may be impacted by various energy policy proposals currently under consideration in Arizona.


•	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.

2019 Operational and Financial Highlights

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


•	Entered into a build-transfer agreement to develop a 247 MW wind-power electric generation facility, which is expected to be completed by December 2020.


•	Filed a general rate case with the ACC based on a test year ended December 31, 2018, which includes a non-fuel retail revenue increase of $115 million.


•	Filed a rate case with the FERC to replace our stated transmission rates with a forward-looking formula rate. The requested forward-looking formula rate will allow for more timely recovery of transmission related costs. On July 31, 2019, FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures.

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RESULTS OF OPERATIONS

Because weather and other factors cause seasonal fluctuations in sales of power, our quarterly results of operations are not indicative of annual results. TEP's summer peak load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first quarter of the year due to mild winter weather in our retail service territory.

The following discussion provides the significant items that affected TEP's results of operations in the second quarter and first six months of 2019 compared with the same periods in 2018. The significant items affecting net income are presented on an after-tax basis.

The second quarter of 2019 compared with the second quarter of 2018

TEP reported net income of $42 million in the second quarter of 2019 compared with net income of $58 million in the second quarter of 2018. The decrease of $16 million, or 27%, was primarily due to:


•	$16 million in lower retail revenue primarily due to a decrease in usage related to unfavorable weather;


•	$3 million in higher depreciation and amortization expense due to an increase in asset base; and


•	$2 million in higher interest expense related to a debt issuance in November 2018.

The decrease was partially offset by:


•	$2 million in higher AFUDC related to an increase in construction projects.

The first six months of 2019 compared with the first six months of 2018

TEP reported net income of $68 million in the first six months of 2019 compared with net income of $81 million in the first six months of 2018. The decrease of $13 million, or 16%, was primarily due to:


•	$13 million in lower retail revenue primarily due to a decrease in usage related to unfavorable weather;


•	$6 million in higher depreciation and amortization expense due to an increase in asset base; and


•	$4 million in higher interest expense related to a debt issuance in November 2018.

The decrease was partially offset by:


•	$4 million in higher AFUDC related to an increase in construction projects;


•	$3 million increase in the value of company-owned life insurance as a result of favorable market conditions; and


•	$2 million in lower income tax expense due to the recognition of additional AMT credits related to a revision in tax law guidance.

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Operating Revenues and Key Statistics

The following table provides key statistics impacting operating revenues:



	Three Months Ended June 30,				Increase (Decrease)		Six Months Ended June 30,				Increase (Decrease)
($ and kWh in millions)	2019		2018		Percent		2019		2018		Percent
Operating Revenues	$	326	$	354	(7.9	)%	$	659	$	629	4.8	%

Electric Sales (kWh)
Retail Sales	2,105		2,343		(10.2	)%	3,941		4,114		(4.2	)%
Wholesale, Long-Term	74		65		13.8	%	209		144		45.1	%
Wholesale, Short-Term	1,606		1,131		42.0	%	3,653		2,230		63.8	%
Total Electric Sales	3,785		3,539		7.0	%	7,803		6,488		20.3	%

Average Revenue Per kWh (Cents/kWh)
Retail	11.21		11.66		(3.9	)%	11.12		11.31		(1.7	)%
Wholesale	2.38		2.92		(18.5	)%	3.17		2.97		6.7	%

Total Retail Customers							427,215		424,242		0.7	%

Operating Revenues decreased by $28 million in the second quarter of 2019 when compared with the same period in 2018 primarily due to: (i) lower retail sales as a result of unfavorable weather; and (ii) a decrease in fuel and purchase power recoveries as a result of lower PPFAC rates. The decrease was partially offset by an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2.

Operating Revenues increased by $30 million in the first six months of 2019 when compared with the same period in 2018 primarily due to an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2. The increase was partially offset by (i) lower retail sales as a result of unfavorable weather; and (ii) a decrease in fuel and purchase power recoveries as a result of lower PPFAC rates.

Short-term wholesale revenues are primarily related to ACC jurisdictional assets and are returned to retail customers by offsetting fuel and purchased power costs eligible for recovery through the PPFAC. Revenues related to Springerville Units 3 and 4 are primarily reimbursements by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with the corresponding expense recorded in Operating Expenses on the Condensed Consolidated Statements of Income.

Operating Expenses

Fuel and Purchased Power Expense

Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, decreased by $15 million, or 12%, in the second quarter when compared with the same period in 2018. The decrease was primarily due to a decrease in: (i) recovery of PPFAC costs as a result of changes in the PPFAC rate; and (ii) price and volumes of non-renewable purchased power. The decrease was partially offset by an increase in generation output.

Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, increased by $36 million, or 17%, in the first six months of 2019 when compared with the same period in 2018. The increase was primarily due to an increase in: (i) generation output; (ii) operating fees related to Gila River Unit 2; and (iii) price of non-renewable purchased power. The increases were partially offset by a decrease in recovery of PPFAC costs as a result of changes in the PPFAC rate.

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The following table presents TEP’s sources of energy and average cost of power by type:



	Three Months Ended June 30,		Increase (Decrease)		Six Months Ended June 30,		Increase (Decrease)
(kWh in millions)	2019	2018	Percent		2019	2018	Percent
Sources of Energy
Coal-Fired Generation	1,606	1,550	3.6	%	3,372	3,264	3.3	%
Gas-Fired Generation	1,850	1,415	30.7	%	3,681	2,297	60.3	%
Utility-Owned Renewable Generation	19	26	(26.9	)%	39	44	(11.4	)%
Total Generation	3,475	2,991	16.2	%	7,092	5,605	26.5	%
Purchased Power, Non-Renewable	254	521	(51.2	)%	674	832	(19.0	)%
Purchased Power, Renewable	205	210	(2.4	)%	350	365	(4.1	)%
Total Generation and Purchased Power	3,934	3,722	5.7	%	8,116	6,802	19.3	%



(cents per kWh)
Average Fuel Cost of Generated Power
Coal	2.42	2.16	12.0	%	2.28	2.46	(7.3	)%
Natural Gas ⁽¹⁾	1.89	1.97	(4.1	)%	2.32	2.09	11.0	%
Average Cost of Purchased Power
Purchased Power, Non-Renewable	2.88	3.08	(6.5	)%	3.63	3.02	20.2	%
Purchased Power, Renewable	9.49	9.49	—	%	9.39	9.40	(0.1	)%


⁽¹⁾	Includes realized gains and losses from hedging activity.

Operations and Maintenance Expense

There were no significant changes to Operations and Maintenance Expense in the second quarter or first six months of 2019 when compared with the same periods in 2018.

Expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income. Expenses related to customer funded renewable energy and DSM programs are collected from customers with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income.

Depreciation and Amortization Expense

Depreciation and Amortization Expense increased by $3 million, or 7%, and $7 million, or 8%, in the second quarter and first six months of 2019, respectively, when compared with the same periods in 2018. The increases were primarily due to higher asset base.

Other Income (Expense)

Other Income (Expense) decreased by $4 million, or 30%, and $3 million, or 13%, in the second quarter and first six months of 2019, respectively, when compared with the same periods in 2018. The decreases were primarily due to an increase in interest expense related to: (i) a debt issuance in November 2018; and (ii) Gila River Unit 2 demand charges, which are recovered through the PPFAC and accounted for as finance lease interest expense. The decreases were partially offset by an increase in: (i) the value of company-owned life insurance as a result of favorable market conditions; and (ii) AFUDC related to an increase in construction projects.

Income Tax Expense

Income Tax Expense decreased by $4 million, or 30%, and $5 million, or 33%, in the second quarter and first six months of 2019, respectively, when compared with the same periods in 2018. The decreases were primarily due to a decrease in earnings before tax expense and the recognition of AMT credits in the first quarter of 2019 related to a revision in tax law guidance.

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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 2018 Annual Report on Form 10-K and new regulatory matters occurring in 2019.

2019 ACC Rate Case

On April 1, 2019, TEP filed a general rate case with the ACC to provide TEP with an opportunity to recover its full cost of service, including an appropriate return on its rate base investments, and enable TEP to continue to provide safe and reliable service. The rate application is based on a test year ended December 31, 2018. We requested new rates be implemented by May 1, 2020.

The key provisions of the rate case include:


•	a non-fuel retail revenue increase of $115 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76 million, or 7.8%, over test year retail revenues;


•	a 7.68% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.35% and an average cost of debt of 4.65%;


•	a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;


•	a request to recover costs of changes in generation resource, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) replacement generation capacity associated with the planned purchase of Gila River Unit 2 and the installation of RICE units at Sundt;


•	a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and


•	a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

TEP cannot predict the outcome of this proceeding.

2019 FERC Rate Case

On May 31, 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing requests that the new rates be implemented by August 1, 2019.

The key provisions of the filing include:


•	replacing TEP's stated transmission rates with a forward-looking formula rate;


•	a 10.4% rate of return on equity; and


•	elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.

The requested forward-looking formula rate will allow for more timely recovery of transmission related costs. Based on the formula rate proposed, TEP anticipates an increase of approximately $7 million over current annual transmission revenue.

On July 31, 2019, FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures.

Abandoned Plant Costs

Also on May 31, 2019, TEP filed with the FERC a request to recover through its OATT rates abandoned plant costs, related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that TEP incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. As of June 30, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Condensed Consolidated Balance Sheets.

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TEP cannot predict the outcome of either of these proceedings.

Temporary Suspension of Residential Service Disconnection

In June 2019, the ACC adopted an emergency rule prohibiting residential service disconnections from June 1, 2019 through October 15, 2019 to address potential health risks from extreme heat. The emergency rule applies to all electric utilities in Arizona subject to ACC jurisdiction. Customers are responsible for paying past due amounts at the end of the moratorium. The ACC also initiated a comprehensive review of its disconnection rules. TEP intends to seek recovery of material costs associated with the suspension of residential service disconnections as well as the costs of complying with future changes in the ACC's disconnection rules.

Federal Income Tax Legislation

Arizona Corporation Commission

In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved the ACC Refund Order effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales. Any over or under collected amounts are deferred to a regulatory asset or liability and will be used to adjust the following year's bill credit amounts.

Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP filed an application with the ACC to establish the 2019 customer refund of $34 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019. TEP is allowed to defer 25% of the 2019 refund into a regulatory liability and 50% of any additional refunds in future years. As part of the 2019 Rate Case, we requested a TEAM that is intended to allow for the timely pass through to our customers of any income tax effects that materially impact revenue requirements as a result of federal or state income tax legislation. TEP has proposed the refunds deferred in the regulatory liability account be returned to customers through the TEAM in the same year the 2019 Rate Case is completed.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 and Liquidity and Capital Resources, Income Tax Position of this Form 10-Q for additional information regarding the ACC Refund Order.

Generation Resources

TEP’s long-term strategy is to transition to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. Recent changes in market conditions, including lower natural gas prices and a decrease in the cost of renewables, have aided this transition. These factors, combined with increasingly stringent environmental requirements, have shifted the preference from coal as a primary fuel source to a more balanced energy portfolio of coal, natural gas, and renewable resources. Going forward, the rate and direction of change in these markets and regulatory regulation is uncertain, and the pace of our energy transition will need to adjust accordingly. These adjustments may include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of these actions.

As of June 30, 2019, approximately 40% of our generation capacity, including owned and leased resources, was from coal-fired generation.

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

Arizona Energy Policy

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy goals, integrated resource planning, and retail competition for generation services. In July 2019, ACC Staff issued proposed modifications to the ACC’s retail electric competition rules. The ACC discussed those rules on July 30, 2019, as part of a scheduled workshop. The adoption of new policies or rules would be subject to rulemaking proceedings at the ACC. We would seek the ACC's approval to recover any costs related to new energy policies or requirements. TEP cannot predict the outcome of these matters or its impact on the Company's financial position or results of operations.

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Navajo Generating Station

In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through 2019 and begin decommissioning activities thereafter. Navajo is expected to shut down on or before December 22, 2019. We are currently recovering Navajo's capital and operating costs in base rates using a useful life through 2030. Due to the early retirement of Navajo, in the 2019 Rate Case we have requested recovery of final retirement costs over a 10-year period. As of June 30, 2019, the net book value of Navajo was $41 million, with estimated other related costs of $4 million.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Navajo.

Sundt Generating Station

In 2017, TEP submitted an Air Quality Permit Application to the Pima County Department of Environmental Quality related to a generation modernization project at Sundt. Under the project, TEP will place in service 10 natural gas RICE units with a total nominal generation capacity of 190 MW. The final permit was issued in December 2018. Construction is underway with the RICE units scheduled for commercial operation by the end of the first quarter of 2020. We have requested recovery of the RICE project costs in the 2019 Rate Case.

The RICE units will balance the variability of intermittent renewable energy resources and will replace 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which are less efficient and lack the quick start, fast ramp capabilities of the RICE units. TEP will discontinue operation of Sundt Units 1 and 2 prior to start-up of the first RICE unit. We are currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives through 2028 and 2030, respectively. Due to the early retirement of Sundt Units 1 and 2, we have requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. As of June 30, 2019, the net book value of Sundt Units 1 and 2 was $27 million, with estimated other related costs of $1 million.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Sundt Units 1 and 2.

Gila River Generating Station

In 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, which includes a three-year option to purchase Gila River Unit 2 (Tolling PPA). TEP anticipates completing the purchase of Gila River Unit 2 in December 2019 for approximately $164 million. We have requested recovery of the Gila River Unit 2 purchase in the 2019 Rate Case. TEP will continue to pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2 until the purchase is complete. TEP recovers the monthly demand charge through the PPFAC mechanism.

We expect the additional 550 MW of capacity, power, and ancillary services from the Tolling PPA to allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduled for early retirement. TEP sells the capacity from the Tolling PPA into the wholesale market on a short-term basis with the associated revenues credited to the PPFAC.

Renewable Generating Facility

In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million. TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence by the third quarter of 2019 and be completed by December 2020. The wind project is expected to qualify for the IRS renewable Production Tax Credit. The credit is expected to recover a minimum of $250 million of the project's costs in the first 10 years and the remaining portion of the credit after the date the facility is placed in service.

Energy Imbalance Market

In May 2019, TEP signed an agreement with the CAISO and plans to begin participating in the EIM by April 2022. The EIM is expected to reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrate renewables, and enhance reliability through improved system utilization and responsiveness.

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Interest Rates

See Part II, Item 7A in our 2018 Annual Report on Form 10-K and Part II, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Cash flows may vary during the year with cash flows from operations being typically the lowest in the first quarter of the year and highest in the third quarter due to TEP's summer peaking load. We use our revolving credit facility as needed to assist in funding our 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 we have access to external financing depends on a variety of factors, including our credit ratings and conditions in the overall capital markets.

Available Liquidity



(in millions)	June 30, 2019
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 and a maturity date of 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: (i) dividend payments; (ii) debt maturities; and (iii) obligations included in the Contractual Obligations and forecasted Capital Expenditures tables reported in our 2018 Annual Report on Form 10-K and the material changes summarized below in the respective sections.

Summary of Cash Flows

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



	Six Months Ended June 30,						Increase (Decrease)
(in millions)	2019			2018			Percent
Operating Activities	$	163		$	198		(17.7	)%
Investing Activities	(221		)	(193		)	14.5	%
Financing Activities	(11		)	(38		)	(71.1	)%
Net Increase (Decrease)	(69		)	(33		)	109.1	%
Beginning of Period	153			50			206.0	%
End of Period ⁽¹⁾	$	84		$	17		394.1	%


⁽¹⁾	Calculated on rounded data and may not correspond exactly to amounts on the Condensed Consolidated Statements of Cash Flows.

Operating Activities

In the first six months of 2019, net cash flows from operating activities decreased by $35 million compared with the same period in 2018. The decrease was primarily due to: (i) lower retail sales as a result of unfavorable weather; (ii) a decrease in recovery of PPFAC costs as a result of changes in the PPFAC rate; and (iii) changes in working capital related to the timing of collections and payments.

Investing Activities

In the first six months of 2019, net cash flows used for investing activities increased by $28 million compared with the same period in 2018 primarily due to an increase in cash paid for capital expenditures in 2019.

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Financing Activities

In the first six months of 2019, net cash flows used for financing activities decreased by $27 million compared with the same period in 2018 primarily due to a decrease in repayments, net of proceeds borrowed, under our revolving credit facility in 2018.

TEP anticipates raising additional capital in the second half of 2019 to: (i) finance the purchase of Gila River Unit 2; (ii) make payments for the development of a wind-powered electric generation facility; and (iii) repay any borrowings under our revolving credit facility, with any remaining balance to be applied to general corporate purposes.

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 June 30, 2019, TEP's short-term investments included highly-rated and liquid money market funds and insured cash sweep accounts.

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 facility 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 June 30, 2019, there was $250 million available under the revolving credit commitments and the LOC facility.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2018 Annual Report on Form 10-K for additional information regarding TEP's credit facility.

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. TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, we may refinance other debt issuances or make additional debt repurchases in the future.

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.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of June 30, 2019, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- and A3, respectively.

Our 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.

Our credit agreement contains pricing based on our credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.

Debt Covenants

Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of June 30, 2019, 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.

Contribution from Parent

TEP received no equity contributions in the second quarter or first six months of 2019 or 2018.

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Dividends Paid to Parent

TEP did not declare or pay dividends to UNS Energy in the second quarter or first six months of 2019 or 2018. On July 22, 2019, TEP declared a $38 million dividend to UNS Energy which was paid July 30, 2019.

Master Trading Agreements

TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or LOCs 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 June 30, 2019, TEP had posted no cash or LOCs as credit enhancements with its counterparties.

Capital Expenditures

TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In the first six months of 2019, there have been no material changes to capital expenditures as reported in our 2018 Annual Report on Form 10-K, except as noted below:

•

In March 2019, we entered into a build-transfer agreement to develop a 247 MW wind-power electric generation facility (Oso Grande), which established the anticipated timing and amount of capital expenditure payments for the Oso Grande project. The agreement contemplates capital expenditures of $259 million in 2019 and $111 million in 2020, compared to $43 million in 2019 and $309 million in 2020, which had been included with respect to this project in the forecasted capital expenditures for renewable energy generation facilities in our 2018 Annual Report on Form 10-K.

Contractual Obligations

In the first six months of 2019, there have been no material changes outside the ordinary course of business to contractual obligations as reported in our 2018 Annual Report on Form 10-K, except as noted below:


•	In March 2019, we entered into a build-transfer agreement to develop Oso Grande, which is expected to be completed by December 2020. The agreement increased our contractual obligations by $259 million in 2019 and $111 million in 2020, contingent upon certain performance obligations.

Off-Balance Sheet Arrangements

Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2018 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

Tax legislation previously in effect included provisions that made qualified property placed in service before 2018 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 were an acceleration of tax benefits we otherwise would have received over a longer period of time and created net operating loss carryforwards that are used to offset future taxable income. As a result, we did not pay any federal or state income taxes in the first six months of 2019. We offset net operating loss carryforwards against taxable income and do not expect to make federal or state income tax payments for the next several years.

Under the TCJA, AMT credit carryforwards will be refunded if not used to offset federal income tax liabilities. TEP received no refunds in the first six months of 2019 and expects to receive refunds of approximately $14 million in 2019, $7 million in 2020, and $3 million in 2021 and 2022.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the TCJA.

Environmental Matters

The 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. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our 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, we are unable to predict the impact they may have on our operations and consolidated

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financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.

Regional Haze Regulations

The Environmental Protection Agency's (EPA) Regional Haze rule requires emission reductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a State Implementation Plan (SIP), and must review and submit revisions to the SIP on a periodic basis.

In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The Arizona Department of Environmental Quality (ADEQ) began to develop a control strategy with a focus on making reasonable progress toward the national visibility goal. In July 2019, the ADEQ notified TEP that Springerville and Sundt had been selected for potential emissions controls evaluation. The evaluations are to be performed for each facility and submitted to ADEQ by December 2019.

TEP will work with ADEQ to prepare and submit the evaluations by the required deadline. Based on current Regional Haze requirement time-frames, TEP anticipates that impacts, if any, to the facilities will likely occur three to five years after the 2021 SIP submittal date. TEP cannot predict the ultimate outcome of these matters at this time.

Greenhouse Gas Regulation

In August 2015, the EPA issued the Clean Power Plan (CPP) limiting CO2 emissions from existing and new fossil fuel-based generation facilities. The CPP established state-level CO2 emission rates and mass-based goals that apply to fossil fuel-based generation. The plan targeted CO2 emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.

In June 2019, the EPA repealed the CPP, and replaced it with the Affordable Clean Energy (ACE) rule, establishing new emissions guidelines. The new rule rebalances the roles between the states and the EPA. Under the new rule, the EPA would set emission guidelines based on the Best System of Emission Reduction (BSER) for Greenhouse Gas (GHG) emissions. The BSER for GHG emissions from existing coal-fired electric utility generating units is defined as heat-rate (efficiency) improvements that can be applied at the source. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the remaining useful life of an individual unit.

States will have three years to submit plans to the EPA establishing performance standards. The EPA has 12 months to act on a complete state submittal. If a state plan is not approved, or a state fails to submit a plan within the allotted three years, the EPA would have two years to issue a federal plan.

TEP does not anticipate a material impact to its facilities at this time. TEP will continue to work with other Arizona utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed.

TEP anticipates that there will be legal challenges, which could delay the effectiveness and implementation of the new rule.

Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) for disposal in landfills and/or surface impoundments. Due to the planned early retirement of Navajo, our share of costs to comply was less than $1 million as of June 30, 2019. We will continue to incur additional operating costs for on-going groundwater monitoring and eventual site closure. Our share of costs to comply at Four Corners is estimated to be $2 million, the majority of which is expected to be capital expenditures associated with site preparation and installation of the groundwater monitoring well system.

In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act, which authorizes the States to establish permit programs under RCRA for implementing regulation for CCR. In response to the WIIN Act and RCRA rulemaking petitions, the EPA has indicated that it intends to conduct two phases of CCR rule revisions. In July 2018, the EPA signed a Phase 1, Part 1 final rule which: (i) revised groundwater protection standards for rule-specific constituents without maximum containment levels; (ii) incorporated risk-based changes under an EPA-approved state permit program or an EPA permit program; and (iii) extended certain closure deadlines. In response to challenges to this rule, the EPA filed a motion to voluntarily remand the rule but not vacate it. On March 13, 2019, the U.S. Court of Appeals for the D.C. Circuit Court issued an order granting the EPA's motion, allowing the EPA nine months to undertake new rulemaking. TEP does not anticipate a

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material impact on operations or financial results from revisions to the Phase 1, Part 1 rule. The EPA anticipates finalizing the Phase 1, Part 2 rule in 2019. The second phase is also anticipated to be finalized in 2019.

On May 3, 2019, the ADEQ filed a Notice of Proposed Expedited Rulemaking to exempt federally regulated CCR disposal units from certain redundant provisions of Arizona’s Aquifer Protection Permit program. TEP is continuing to work with other affected utilities and the ADEQ 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 results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that there have been no significant changes during the six months ended June 30, 2019, 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 2018 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

For a discussion of new accounting pronouncements affecting TEP, see Note 1 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 2018 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 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures were effective as of June 30, 2019.

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 June 30, 2019, 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 7 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 2018 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 2018 Form 10-K.

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ITEM 6. EXHIBITS



EXHIBIT INDEX
Exhibit No.		Description
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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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

104		The cover page from the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in Inline XBRL



*	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:	August 1, 2019	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)