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~~March 31, 2020

☐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.~~May 5, 2020.

Table of Contents

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS



2015 Credit Agreement		The 2015 Credit Agreement provides for a $250 million revolving credit and letter of credit facilities with a sublimit of $50 million; the credit agreement matures in October 2022
2019 Credit Agreement		The 2019 Credit Agreement provided for $225 million in term loans. In April 2020, the term loans were repaid and the agreement terminated
2019 ACC Rate Case		~~A pending~~In April 2019, TEP filed a general rate case ~~filed~~ with the ACC ~~by TEP in April~~ based on a test year ended December 31, 2018
2019 ~~requesting new rates be implemented in May 2020~~FERC Rate Case		In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings
ABR		Alternate Base Rate
ACC		Arizona Corporation Commission
ACC Refund Order		An order issued in 2018 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~~credits and a regulatory liability deferral that reflects ~~the deferral of~~ the return of a portion of the savings, effective May 1, 2018
~~AFUDC~~ADEQ		~~Allowance for Funds Used During Construction~~Arizona Department of Environmental Quality
ALJ		Administrative Law Judge
AMT		Alternative Minimum Tax
~~CAISO~~COVID-19		~~California Independent System Operator~~Coronavirus Disease 2019
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
LIBOR		London Interbank Offered Rate
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



Oso Grande		A 247 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico
San Juan		San Juan Generating Station
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), a measure of the quantity of heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit at the temperature at which water has its greatest density, in billions
GWh		Gigawatt-hour(s), a measure of electricity that represents one billion watts of power expended over one hour
kWh		Kilowatt-hour(s), a measure of electricity that represents one thousand watts of power expended over one hour
MW		Megawatt(s)
~~MWh~~		~~Megawatt-hour(s)~~, a measure of electricity that represents one million watts of power

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~~2019 Annual Report on 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 and any change in the structure of utility service in Arizona resulting from the ACC's examination of the state's 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~~PPAs 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;~~capital and use the proceeds from any capital that we do raise as originally intended; 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; participation in the Energy Imbalance Market; the extent of the impact of the COVID-19 pandemic on our business and operations, and the economic and societal disruptions resulting from the COVID-19 pandemic; 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,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Operating Revenues	$	326,091		$	354,246		$	659,094		$	629,336		$	278,556		$	333,003

Operating Expenses
Fuel	75,441			62,870			164,859			130,893			63,299			89,418
Purchased Power	27,345			32,389			60,195			52,753			18,318			32,850
Transmission and Other PPFAC Recoverable Costs	12,094			9,909			24,019			19,700			10,595			11,925
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(10,918		)	13,372			(4,713		)	5,406			(1,182		)	6,205
Total Fuel and Purchased Power	103,962			118,540			244,360			208,752			91,030			140,398
Operations and Maintenance	92,045			93,445			178,633			176,601			87,455			86,588
Depreciation	41,427			39,418			82,744			78,294			46,499			41,317
Amortization	7,397			6,021			15,014			12,042			6,956			7,617
Taxes Other Than Income Taxes	14,120			14,299			28,321			28,479			14,909			14,201
Total Operating Expenses	258,951			271,723			549,072			504,168			246,849			290,121

Operating Income	67,140			82,523			110,022			125,168			31,707			42,882

Other Income (Expense)
Interest Expense	(22,144		)	(16,707		)	(44,275		)	(33,192		)	(20,481		)	(22,131		)
Allowance For Borrowed Funds	1,303			706			2,577			1,393			2,882			1,274
Allowance For Equity Funds	3,398			1,532			6,721			3,177			3,034			3,323
Unrealized Gains (Losses) on Investments													(6,427		)	3,080
Other, Net	842			1,679			4,130			1,255			853			208
Total Other Income (Expense)	(16,601		)	(12,790		)	(30,847		)	(27,367		)	(20,139		)	(14,246		)

Income Before Income Tax Expense	50,539			69,733			79,175			97,801			11,568			28,636
Income Tax Expense	8,476			12,136			10,917			16,401			3,650			2,441
Net Income	$	42,063		$	57,597		$	68,258		$	81,400		$	7,918		$	26,195

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,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
Comprehensive Income
Net Income	$	42,063	$	57,597	$	68,258	$	81,400	$	7,918	$	26,195
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
Net of Income Tax Expense of $0 and $9									—		28
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
Net of Income Tax Expense of $45 and $22									135		66
Total Other Comprehensive Income, Net of Tax	90		213		184		451		135		94
Total Comprehensive Income	$	42,153	$	57,810	$	68,442	$	81,851	$	8,053	$	26,289

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,						Three Months Ended March 31,
	2019			2018			2020			2019
Cash Flows from Operating Activities
Net Income	$	68,258		$	81,400		$	7,918		$	26,195
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	82,744			78,294			46,499			41,317
Amortization Expense	15,014			12,042			6,956			7,617
Amortization of Debt Issuance Costs	1,153			1,168			612			571
Use of Renewable Energy Credits for Compliance	18,624			15,132			10,773			8,275
Deferred Income Taxes	14,244			21,924			10,567			4,191
Pension and Other Postretirement Benefits Expense	8,881			7,668			3,721			4,440
Pension and Other Postretirement Benefits Funding	(6,431		)	(5,708		)	(1,310		)	(1,744		)
Allowance for Equity Funds Used During Construction	(6,721		)	(3,177		)	(3,034		)	(3,323		)
Regulatory Deferral, ACC Refund Order	3,156			—			4,259			1,707
Changes in Current Assets and Current Liabilities:
Accounts Receivable	5,910			(41,534		)	29,646			25,319
Materials, Supplies, and Fuel Inventory	(4,689		)	8,102			7,028			(3,537		)
Regulatory Assets	(151		)	(5,008		)	(6,399		)	(3,400		)
Other Current Assets	1,766			(1,677		)	2,079			(9,449		)
Accounts Payable and Accrued Charges	(32,061		)	16,385			(31,905		)	(22,687		)
Income Taxes Receivable	(3,326		)	(5,521		)
Income Taxes Receivable, Net							(7,185		)	(1,424		)
Regulatory Liabilities	(4,507		)	17,180			3,338			6,587
Other, Net	969			1,117			7,463			1,078
Net Cash Flows—Operating Activities	162,833			197,787			91,026			81,733
Cash Flows from Investing Activities
Capital Expenditures	(199,791		)	(174,810		)	(364,012		)	(106,279		)
Purchase Intangibles, Renewable Energy Credits	(24,793		)	(25,848		)	(10,625		)	(9,704		)
Contributions in Aid of Construction	3,932			7,773			1,592			2,852
Net Cash Flows—Investing Activities	(220,652		)	(192,885		)	(373,045		)	(113,131		)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	—			66,000			105,000			—
Repayments of Borrowings, Revolving Credit Facility	—			(93,000		)	(20,000		)	—
Proceeds from Borrowings, Term Loan							60,000			—
Payments of Finance Lease Obligations	(10,889		)	(10,930		)	(11,535		)	(10,889		)
Contribution from Parent							150,000			—
Other, Net	(166		)	(3		)	599			383
Net Cash Flows—Financing Activities	(11,055		)	(37,933		)	284,064			(10,506		)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash	(68,874		)	(33,031		)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash							2,045			(41,904		)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	152,747			49,501			28,472			152,747
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	83,873		$	16,470		$	30,517		$	110,843

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			March 31, 2020			December 31, 2019
ASSETS
Utility Plant
Plant in Service	$	6,126,496		$	6,020,469		$	6,813,518		$	6,663,912
Utility Plant Under Finance Leases	248,635			248,635			151,467			151,467
Construction Work in Progress	298,115			258,965			490,975			303,488
Total Utility Plant	6,673,246			6,528,069			7,455,960			7,118,867
Accumulated Depreciation and Amortization	(2,337,169		)	(2,293,783		)	(2,537,262		)	(2,506,686		)
Accumulated Amortization of Finance Lease Assets	(79,829		)	(73,646		)	(79,722		)	(77,285		)
Total Utility Plant, Net	4,256,248			4,160,640			4,838,976			4,534,896

Investments and Other Property	55,479			50,952			54,210			62,136

Current Assets
Cash and Cash Equivalents	69,692			138,114			12,234			9,762
Accounts Receivable, Net	159,165			172,367
Accounts Receivable (Net of Allowance for Credit Losses of $5,698 and $5,716)							124,738			154,847
Fuel Inventory	26,131			22,783			25,831			23,731
Materials and Supplies	109,331			107,990			112,414			121,542
Regulatory Assets	118,699			106,725			137,126			138,412
Derivative Instruments	7,216			3,929			4,139			3,596
Other	27,131			25,571			26,514			21,416
Total Current Assets	517,365			577,479			442,996			473,306
Regulatory and Other Assets
Regulatory Assets	292,068			293,078			324,526			326,860
Derivative Instruments	11,428			8,402			5,934			2,763
Other	85,351			68,656			86,929			89,196
Total Regulatory and Other Assets	388,847			370,136			417,389			418,819
Total Assets	$	5,217,939		$	5,159,207		$	5,753,571		$	5,489,157

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			March 31, 2020			December 31, 2019
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
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2020 and December 31, 2019)							$	1,546,539		$	1,396,539
Capital Stock Expense	(6,357		)	(6,357		)	(6,357		)	(6,357		)
Retained Earnings	552,535			484,277			603,710			595,792
Accumulated Other Comprehensive Loss	(4,530		)	(4,714		)	(7,636		)	(7,771		)
Total Common Stock Equity	1,888,187			1,819,745			2,136,256			1,978,203
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2019 and December 31, 2018)	—			—
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2020 and December 31, 2019)							—			—
Finance Lease Obligations	6,192			19,773			—			67,316
Long-Term Debt, Net	1,616,205			1,615,252			1,522,326			1,522,087
Total Capitalization	3,510,584			3,454,770			3,658,582			3,567,606
Current Liabilities
Current Maturities of Long-Term Debt, Net							80,356			80,330
Borrowings Under Credit Agreements, Net							309,913			165,000
Finance Lease Obligations	175,202			172,510			72,868			17,086
Accounts Payable	105,712			133,012			99,268			136,465
Accrued Taxes Other than Income Taxes	40,499			41,686			54,783			42,741
Accrued Employee Expenses	25,393			34,339			20,637			32,567
Accrued Interest	17,548			17,927			17,067			16,700
Regulatory Liabilities	89,898			95,094			99,593			96,017
Customer Deposits	25,191			27,650			22,512			24,568
Derivative Instruments	31,242			18,137			21,264			27,615
Other	24,204			21,555			24,583			23,678
Total Current Liabilities	534,889			561,910			822,844			662,767
Regulatory and Other Liabilities
Deferred Income Taxes, Net	390,831			369,705			444,080			432,484
Regulatory Liabilities	497,572			512,425			475,232			477,495
Pension and Other Postretirement Benefits	116,306			117,472			133,937			133,452
Derivative Instruments	29,868			19,361			51,100			48,697
Other	137,889			123,564			167,796			166,656
Total Regulatory and Other Liabilities	1,172,466			1,142,527			1,272,145			1,258,784

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	5,217,939		$	5,159,207		$	5,753,571		$	5,489,157

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

(Concluded)

TUCSON ELECTRIC POWER COMPANY

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

(Amounts in thousands)

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
													Common Stock		Capital Stock Expense			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholder's Equity
Balances as of December 31, 2018													$	1,346,539	$	(6,357	)	$	484,277	$	(4,714	)	$	1,819,745
Net Income						42,063					42,063							26,195					26,195
Other Comprehensive Income, Net of Tax								90			90									94			94
Balances as of June 30, 2019	$	1,346,539	$	(6,357	)	$	552,535	$	(4,530	)	$	1,888,187
Balances as of March 31, 2019													$	1,346,539	$	(6,357	)	$	510,472	$	(4,620	)	$	1,846,034

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
Balances as of December 31, 2019													$	1,396,539	$	(6,357	)	$	595,792	$	(7,771	)	$	1,978,203
Net Income						68,258					68,258							7,918					7,918
Other Comprehensive Income, Net of Tax								184			184									135			135
Balances as of June 30, 2019	$	1,346,539	$	(6,357	)	$	552,535	$	(4,530	)	$	1,888,187
Contribution from Parent													150,000										150,000
Balances as of March 31, 2020													$	1,546,539	$	(6,357	)	$	603,710	$	(7,636	)	$	2,136,256

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

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~~432,000 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~~Securities and Exchange Commission's (SEC) interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP 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~~2019 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. Most notably, TEP bifurcated Other, Net on the Condensed Consolidated Statements of Income as follows:



	As Filed		Amount Reclassified			As Reclassified
(in thousands)	Three Months Ended March 31, 2019
Other Income (Expense)
Other, Net	$	3,288	$	(3,080	)	$	208
Unrealized Gains (Losses) on Investments	—		3,080			3,080

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a ~~VIE,~~Variable Interest Entity (VIE), and if itTEP 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~~has entered 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,~~March 31, 2020, the carrying amounts of assets and liabilities inon 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~~TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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,				March 31,
(in millions)	2019		2018		2020		2019
Cash and Cash Equivalents	$	70	$	6	$	12	$	96
Restricted Cash included in:
Investments and Other Property	13		9		16		14
Current Assets—Other	1		1		3		1
Total Cash, Cash Equivalents, and Restricted Cash	$	84	$	16	$	31	$	111

~~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.~~2020. 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~~Credit Losses

TEP adopted accounting guidance that requires ~~lessees~~entities to ~~recognize~~incorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a ~~lease liability, initially measured at the present value of future lease payments,~~financial instrument, in addition to using past events and ~~a right-of-use asset for all leases with a lease term greater than 12 months.~~current conditions. The new ~~lease standard~~guidance also requires ~~additional~~ quantitative and qualitative disclosures regarding the activity in the allowance for ~~both lessees and lessors. TEP applied~~credit losses for financial assets within the ~~transition provisions~~scope 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.guidance. See Note 64 for additional disclosure about ~~TEP’s leasing arrangements.~~

~~Internal-Use Software~~

~~TEP early adopted accounting guidance that clarifies accounting~~TEP's allowance 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.credit losses.

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 TEP's business decisions and accounting practices. The FERC regulates ~~the terms~~rates and ~~prices of~~services for electric transmission ~~services~~ and wholesale ~~electricity sales.~~power sales in interstate commerce.

2019 ACC RATE CASE

OnIn 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~~TEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019, include:

a non-fuel retail revenue increase of ~~$115~~$99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of ~~$76~~$60 million ~~or 7.8%,~~ over test year retail revenues;

a ~~7.68%~~7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of ~~10.35%~~10.00% and an average cost of debt of 4.65%;

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 the Sundt RICE ~~units at Sundt;~~

~~Table of Contents~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

Units;

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.

Hearings before an ALJ were held in January and February 2020, and are scheduled to resume in June 2020 to address the request for inclusion of cost recovery in rates for Gila River Unit 2 and the Sundt RICE Units. As a result of work schedule disruptions arising from the COVID-19 pandemic, the timing of when new rates will go into effect is uncertain.

TEP cannot predict the outcome of the proceeding.

2019 FERC RATE CASE

~~On May 31,~~In 2019, ~~TEP filed a proposal with~~ the FERC ~~requesting~~issued an order approving TEP's proposed OATT revisions ~~to its OATT. The filing requests that the proposed revisions be implemented by~~effective August 1, ~~2019.~~2019, subject to refund and further proceedings.

~~The key proposals~~Provisions of the ~~filing include:~~order include, but are not limited to:

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~~is intended to allow for a more timely recovery of transmission related costs.

~~On July 31, 2019,~~ As part of the order, the FERC ~~issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and~~ established hearing and settlement procedures. All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. TEP had reserved $6 million as of March 31, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. 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~~credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, ~~2018.~~2018 (ACC Refund Order). The ~~refund~~ACC Refund Order 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.

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



	Three Months Ended March 31,
(in millions)	2020			2019
Beginning of Period	$	—		$	4
ACC Approved Refund (Reduction in Operating Revenues)	(7		)	(7		)
Amount Returned to Customers Through Bill Credits	3			4
Regulatory Deferral	4			2
End of Period	$	—		$	3

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~~informational filing with the ACC to establish a ~~2019~~2020 customer refund of ~~$34~~$35 million.

The ~~table below summarizes the regulatory asset (liability) balance related~~refund will be returned 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 )

customers

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our rate case. A regulatory liability balance related to the deferred TCJA customer refunds of $12 million as of March 31, 2020, and $8 million as of December 31, 2019, was recorded in Regulatory and Other Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets.

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 typically adjusted annually ~~each~~on 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,						Three Months Ended March 31,
(in millions)	2019			2018			2019			2018			2020			2019
Beginning of Period	$	(22	)	$	(4	)	$	(17	)	$	(9	)	$	36		$	(17	)
Deferred Fuel and Purchased Power Costs ⁽¹⁾	6			(11		)	3			(9		)	48			53
PPFAC Refunds (Recoveries) ⁽²⁾	7			(3		)	5			—
PPFAC and Base Power Recoveries ⁽²⁾													(48		)	(58		)
End of Period	$	(9	)	$	(18	)	$	(9	)	$	(18	)	$	36		$	(22	)


⁽¹⁾	~~The negative balance in Deferred Fuel~~Includes costs eligible for recovery through the PPFAC and ~~Purchased Power Costs represents a decrease in the actual cost of fuel and purchased~~base power ~~below the costs associated with base recoveries.~~rates.


⁽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. In March 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, effective June 1, 2020.

Renewable Energy Standard

The ACC’s ~~RES~~Renewable Energy Standard (RES) requires ~~Arizona regulated~~Arizona-regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2020 is 9%10% of retail electric sales, ~~in 2019 and increases~~which will increase annually until renewable retail sales represent at least 15% by ~~2025, with~~2025. DG ~~accounting~~will account 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,~~2019, the ACC approved TEP's ~~2018~~2019 RES implementation plan with a budget amount of ~~$54 million, which is recovered through the RES surcharge.~~$55 million. The recovery ~~funds the following:~~funds: (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.~~Energy Efficiency Standards (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~~2020 and ~~2018~~2019 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.~~surcharge, and approved a waiver of the 2018 EE Standard. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans.

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.~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

occurred. 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 increase cap of 2% of TEP's applicable retail revenues.

~~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,				Three Months Ended March 31,
(in millions)	2019		2018		2019		2018		2020		2019
LFCR Revenues	$	6	$	5	$	16	$	13	$	12	$	10

REGULATORY ASSETS AND LIABILITIES

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


($ in millions)	Remaining Recovery Period (years)	June 30, 2019		December 31, 2018		Remaining Recovery Period (years)	March 31, 2020		December 31, 2019
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	123	$	126	Various	$	133	$	135
Early Generation Retirement Costs ⁽¹⁾	Various	67		72		Various	66		68
Derivatives (Note 9)	11	47		27		10	64		72
Income Taxes Recoverable through Future Rates ⁽²⁾	Various	44		47
Lost Fixed Cost Recovery	2	42		35		2	53		46
Income Taxes Recoverable through Future Rates ⁽¹⁾						Various	37		38
Under Recovered Purchased Energy Costs						1	36		36
Property Tax Deferrals ⁽⁴⁾⁽²⁾						1	25		24
Final Mine Reclamation and Retiree Healthcare Costs ⁽³⁾	19	26		29		19	21		19
Property Tax Deferrals ⁽⁴⁾⁽²⁾	1	24		23
Springerville Unit 1 Leasehold Improvements⁽⁵⁾	4	10		11
Springerville Unit 1 Leasehold Improvements⁽⁴⁾						3	8		9
Other Regulatory Assets	Various	28		30		Various	19		18
Total Regulatory Assets		411		400			462		465
Less Current Portion	1	119		107		1	137		138
Total Non-Current Regulatory Assets		$	292	$	293		$	325	$	327


Regulatory Liabilities				��
Income Taxes Payable through Future Rates ⁽²⁾⁽¹⁾	Various	$	344	$	354	Various	$	325	$	327
Net Cost of Removal ⁽⁶⁾⁽⁵⁾	Various	162		171		Various	159		164
Renewable Energy Standard	Various	53		52		Various	59		59
Purchased Power and Fuel Adjustment Clause	1	9		17
Deferred Investment Tax Credits ⁽⁷⁾	Various	7		7
Deferred Investment Tax Credits ⁽⁶⁾						Various	3		3
Other Regulatory Liabilities	Various	13		6		Various	29		20
Total Regulatory Liabilities		588		607			575		573
Less Current Portion	1	90		95		1	100		96
Total Non-Current Regulatory Liabilities		$	498	$	512		$	475	$	477

⁽¹⁾

~~Includes~~Amortized over 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~~lives 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.assets.


⁽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~~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.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


⁽⁵⁾⁽³⁾	Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully 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⁾	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 and reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)


⁽⁶⁾⁽⁵⁾	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⁾⁽⁶⁾	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.

PLANT IN SERVICE

Under an air permit approved by the Pima County Department of Environmental Quality, TEP placed in service 5 natural gas RICE units at Sundt in December 2019 and an additional 5 units in March 2020. As of March 31, 2020 and December 31, 2019, there was $178 million and $82 million, respectively, related to the Sundt RICE Units recorded in Plant in Service on the Condensed Consolidated Balance Sheets. The 10 units have a total nominal generation capacity of 188 MW.

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,				Three Months Ended March 31,
(in millions)	2019		2018		2019		2018		2020		2019
Retail	$	236	$	273	$	438	$	465	$	192	$	202
Wholesale(1)	43		35		127		73		36		84
Other Services	30		27		54		50		24		24
Revenues from Contracts with Customers	309		335		619		588		252		310
Alternative Revenues	6		5		18		15		14		12
Other	11		14		22		26		13		11
Total Operating Revenues	$	326	$	354	$	659	$	629	$	279	$	333


⁽¹⁾	In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the 2019 FERC Rate Case.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



(in millions)	March 31, 2020			December 31, 2019
Retail	$	52		$	61
Retail, Unbilled	32			42
Retail, Allowance for Credit Losses	(6		)	(6		)
Wholesale⁽¹⁾	22			31
Due from Affiliates (Note 5)	11			8
Other	14			19
Accounts Receivable	$	125		$	155


⁽¹⁾	Includes $3$5 million as of ~~June 30, 2019,~~March 31, 2020 and ~~$8 million as of~~ December 31, ~~2018,~~2019, of receivables related to revenue from derivative instruments.

Allowance for Credit Losses

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~ TEP records an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. Based on these factors, TEP has not recorded an allowance for credit losses on non-retail trade receivables as of March 31, 2020 and December 31, 2019. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets:



	Three Months Ended
(in millions)	March 31, 2020
Beginning of Period	$	(6	)
Credit Loss Expense	(1		)
Write-offs	1
End of Period	$	(6	)

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~~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		March 31, 2020		December 31, 2019
Receivables from Related Parties
UNS Electric	$	4	$	7	$	5	$	6
UNS Energy					5		—
UNS Gas	2		1		1		2
Total Due from Related Parties	$	6	$	8	$	11	$	8

Payables to Related Parties
SES	$	2	$	2	$	4	$	2
UNS Electric					2		1
UNS Energy	2		1		1		1
UNS Electric	—		1
UNS Gas	—		1
Total Due to Related Parties	$	4	$	5	$	7	$	4

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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,				Three Months Ended March 31,
(in millions)	2019		2018		2019		2018		2020		2019
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric ⁽¹⁾	$	2	$	1	$	3	$	3	$	2	$	1
Control Area Services, UNS Electric ⁽²⁾	1		1		2		1		1		1
Common Costs, UNS Energy Affiliates ⁽³⁾	5		5		10		9		5		5

Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES ⁽⁴⁾	4		4		7		7		4		3
Corporate Services, UNS Energy ⁽⁵⁾	2		1		3		3		1		1
Corporate Services, UNS Energy Affiliates ⁽⁶⁾	1		1		2		3		1		1
Capacity Charges, UNS Gas ⁽⁷⁾									—		1


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


⁽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~~ $2 million for the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018, respectively.~~

2019.


⁽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.


⁽⁷⁾	UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~DIVIDENDS PAID TO~~CONTRIBUTION FROM PARENT

On ~~July 22, 2019, TEP declared a $38 million dividend to~~April 27, 2020, UNS Energy ~~which was~~approved an equity contribution up to $100 million to TEP to be paid ~~July~~on or before June 30, ~~2019.~~2020.

NOTE 6. ~~LEASES~~DEBT AND CREDIT AGREEMENTS

~~When~~There have been no significant changes to TEP's debt or credit agreements from those reported in its 2019 Annual Report on Form 10-K, except as noted below.

DEBT

Issuance

In April 2020, TEP issued and sold $350 million aggregate principal amount of 4.00% unsecured senior notes due June 2050. TEP may call the debt prior to December 15, 2049, with a ~~contract conveys~~make-whole premium plus accrued interest. After December 15, 2049, TEP may call the ~~right~~debt at par plus accrued interest. TEP used the net proceeds from the sale to ~~control~~repay amounts outstanding under its credit agreements, and intends to use the ~~use of an identified asset~~remaining balance 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.~~general corporate purposes.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

CREDIT AGREEMENTS

2019 Credit Agreement

AsThe following table presents components of ~~June 30,~~TEP's unsecured 2019 ~~TEP had~~Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:



	Capacity		Borrowed		Available		Weighted Average Interest Rate		Pricing
(in millions)	March 31, 2020
Term Loan	$	225	$	225	$	—	1.30	%	LIBOR + 0.550%	or ABR + 0.00%

In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the outstanding term loans and terminate such agreement.

2015 Credit Agreement

The following ~~future minimum lease payments, excluding payments to lessors for variable costs:~~table presents components of TEP's unsecured 2015 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:

(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



	Capacity		Sub-Limit LOC		Borrowed ⁽¹⁾		Available		Weighted Average Interest Rate		Pricing ⁽²⁾
(in millions)	March 31, 2020
Revolver and LOC	$	250	$	50	$	97	$	153	1.75	%	LIBOR + 1.000%	or ABR + 0.00%


⁽¹⁾	Includes ~~monthly demand charge payments~~$12 million in LOCs issued in January 2020 pursuant to ~~SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.~~TEP taking ownership of Oso Grande under the build-transfer agreement.

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



⁽²⁾	~~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~~	%Interest rates and fees are based on a pricing grid tied to TEP's credit rating.

~~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.

~~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~~May 5, 2020, there was $238 million available under the ~~three~~revolving credit commitments 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.LOC facilities.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

~~In addition~~There have been no significant changes to TEP's long-term commitments from those reported in its ~~2018~~2019 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

~~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~~timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP ~~will~~ prospectively ~~adjust~~adjusts 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~~defers these ~~costs as a regulatory asset~~expenses until recovered from customers 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.~~paid.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of final mine reclamation costs at both mines is $57 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $37 million as of March 31, 2020, and $36 million as of December 31, 2019, was recorded in Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

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 no0 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,~~March 31, 2020, there have been no0 such payment defaults under any of the participation agreements. The San Juan participation ~~agreements expire in: (i) December~~agreement expires in 2022, Four Corners in 2041, and Luna in 2046.

The Navajo participation agreement expired in 2019, ~~at Navajo; (ii) 2022 at San Juan; (iii) 2041 at Four Corners; and (iv) 2046 at Luna.~~but certain performance obligations continue through the decommissioning of the generating station. Relative to the Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party.

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

Broadway-Pantano Site

The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized.

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


											Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,										Three Months Ended March 31,
(in millions)	2019			2018			2019		2018		2020			2019			2020		2019
Service Cost	$	6		$	7		$	2	$	2	$	4		$	3		$	1	$	1
Non-Service Cost⁽¹⁾
Interest Cost	9			8			1		1		4			4			—		—
Expected Return on Plan Assets	(13		)	(14		)	—		—		(7		)	(6		)	—		—
Amortization of Net Loss	4			4			—		—		2			2			—		—
Net Periodic Benefit Cost	$	6		$	5		$	3	$	3	$	3		$	3		$	1	$	1


⁽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. TEP has no financial instruments categorized as Level 3.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income 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			Total
(in millions)	March 31, 2020
Assets
Restricted Cash ⁽¹⁾	$	18	$	—		$	18
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		8			8
Energy Derivative Contracts, No Regulatory Recovery ⁽²⁾	—		2			2
Total Assets	18		10			28
Liabilities
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		(72		)	(72		)
Total Liabilities	—		(72		)	(72		)
Total Assets (Liabilities), Net	$	18	$	(62	)	$	(44	)


	Level 1		Level 2			Level 3			Total
(in millions)	June 30, 2019											December 31, 2019
Assets
Cash Equivalents ⁽¹⁾	$	67	$	—		$	—		$	67
Restricted Cash ⁽¹⁾	14		—			—			14			$	18	$	—		$	18
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		10			3			13			—		3			3
Energy Derivative Contracts, No Regulatory Recovery ⁽²⁾	—		—			6			6			—		3			3
Total Assets	81		10			9			100			18		6			24
Liabilities
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		(48		)	(13		)	(61		)	—		(76		)	(76		)
Total Liabilities	—		(48		)	(13		)	(61		)	—		(76		)	(76		)
Total Assets (Liabilities), Net	$	81	$	(38	)	$	(4	)	$	39		$	18	$	(70	)	$	(52	)

~~Table of Contents~~

~~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~~represents 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 inon the balance sheet. The tables below present the potential offset of counterparty netting and cash ~~collateral.~~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			Gross Amount Not Offset in the Balance Sheets					Net Amount
				Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted								Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted
(in millions)	June 30, 2019											March 31, 2020
Derivative Assets
Energy Derivative Contracts	$	19		$	13		$	—	$	6		$	10		$	9		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(61		)	(13		)	—		(48		)	(72		)	(9		)	—		(63		)


(in millions)	December 31, 2018											December 31, 2019
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1		$	6		$	4		$	—		$	2
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)	(76		)	(4		)	(2		)	(70		)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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~~TEP 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~~TEP primarily

~~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,						Three Months Ended March 31,
(in millions)	2019			2018			2019			2018			2020		2019
Unrealized Net Gain (Loss)	$	(11	)	$	(14	)	$	(20	)	$	(32	)	$	9	$	(9	)

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~~Derivative revenues 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

Income are not material to TEP's financial position or results of operation for the three months ended March 31, 2020 and 2019.

Derivative Volumes

As of ~~June 30, 2019,~~March 31, 2020, 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	March 31, 2020	December 31, 2019
Power Contracts GWh	5,836	1,743	4,118	4,740
Gas Contracts BBtu	138,837	146,933	117,261	122,779

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~~As of March 31, 2020 and December 31, 2019, TEP did not have any 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 $ 9
$ (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.~~

balances. 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:~~March 31, 2019:



	Three Months Ended
(in millions)	March 31, 2019
Beginning of Period	$	1
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(8		)
Settlements	1
End of Period	$	(6	)

Gains (Losses), Assets (Liabilities) Still Held	$	(7	)

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;~~limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or ~~(iii) a failure to meet certain financial ratios.~~(iv) unfavorable changes in counterparties' assessment of TEP's credit strength. In the event that such credit events were to occur, ~~the Company,~~TEP, 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~~$76 million as of ~~June 30, 2019,~~March 31, 2020, compared with ~~$41~~$100 million as of December 31, ~~2018.~~2019. As of ~~June 30, 2019,~~March 31, 2020, TEP had no0 collateral posted ~~with its counterparties.~~related to energy procurement or hedging activities. If the credit risk contingent features were triggered on ~~June 30, 2019,~~March 31, 2020, TEP would have been required to post an additional ~~$84~~$76 million of collateral of which ~~$15~~$8 million relates to outstanding net payable balances for settled positions.

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~~Due to the short-term nature of ~~these financial instruments. These items~~borrowings under revolving credit facilities approximating fair value, they 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~~net carrying value and estimated fair value of TEP's long-term debt:


	Fair Value Hierarchy	Face Value				Fair Value				Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018			March 31, 2020		December 31, 2019		March 31, 2020		December 31, 2019
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,629	$	1,629	$	1,745	$	1,672	Level 2	$	1,603	$	1,602	$	1,716	$	1,755

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;

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

~~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.~~GAAP.

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 actual future results to differ from those we currently ~~expect or~~ anticipate, see Forward-Looking Information at the front of this ~~Form 10-Q~~report and Risk Factors in Part 1, Item 1A of our ~~2018~~2019 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~~performance 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, affordable, 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 reliability and 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~~achieving 30% of our customers’ energy needs with non-carbon emitting resources ~~by 2030.~~eight years ahead of our 2030 goal. We are currently working on new long-term goals based on carbon emission reductions as part of our integrated resource plan, which we plan to file with the ACC during 2020. 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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Table of Contents

~~RESULTS OF OPERATIONS~~CURRENT ECONOMIC CONDITIONS—COVID-19

~~Because weather~~In March 2020, the World Health Organization declared COVID-19 a pandemic. Also in March 2020, Arizona's governor issued a declaration of a Public Health State of Emergency followed by a statewide school closure and ~~other factors cause seasonal fluctuations~~temporary closure of non-essential businesses. We are monitoring the COVID-19 pandemic and taking steps intended to mitigate the potential risks to our workforce and our business. This pandemic has disrupted economic activity in ~~sales~~TEP’s service territory as well as capital markets. These disruptions could continue for a prolonged period of ~~power,~~time or become severe. We are executing our ~~quarterly~~business continuity plans, which include actions intended to aid in the prevention of the spread of COVID-19 among our employees and customers, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Actions we have taken include: (i) increased precautions with regard to employee and facility hygiene for field crews and others who must continue working on premise; (ii) imposed travel limitations on employees; (iii) directed employees to work remotely whenever possible; (iv) pre-work screening procedures conducted prior to entering our facilities; (v) distributed face masks to workforce; and (vi) restricted access to critical facilities. Additional safety protocols are being implemented for work required within customer premises that are intended to aid in the protection of our employees, our customers, and the community.

Recognizing the potential effect that the COVID-19 pandemic could have on many customers’ ability to pay their bills and the need for continued utility service, we temporarily suspended service disconnections and late fees for non-payment of bills until further notice. In addition, we filed a request with the ACC to refund to customers approximately $8 million of over-collected DSM funds in excess of program expenditures. The proposed refund would be in the form of a temporary reduction to the existing DSM surcharge distributed over a two-month period beginning in May 2020. We are also working with our suppliers, vendors, and contractors to assess and mitigate potential impacts to the procurement of goods and services.

The COVID-19 pandemic is a rapidly evolving situation. We cannot predict the duration of the pandemic or the ultimate effects of it on the global, national, or local economy. We will continue to monitor developments affecting our workforce, customers, suppliers, and operations and take additional measures as we believe are warranted. Through the first three months of 2020, we have not experienced a material impact to our results of operations ~~are not indicative of annual results. TEP's summer peak load occurs during the third quarter~~as a result 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~~COVID-19 pandemic.

Performance - 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~~three months of ~~2019~~2020 compared with the ~~same periods in 2018. The significant items affecting net income are presented on an after-tax basis.~~

~~The second quarter of2019 compared with the second quarter~~first three months of ~~2018~~2019

TEP reported net income of ~~$42~~$8 million in the ~~second quarter~~first three months of ~~2019~~2020 compared with net income of ~~$58~~$26 million in the ~~second quarter~~first three months of ~~2018.~~2019. The decrease of ~~$16~~$18 million, or ~~27%~~70%, was primarily due to:

$1610 million ~~in lower retail revenue primarily due to a~~ decrease in ~~usage related~~value of investments used to support certain post-employment benefits as a result of unfavorable ~~weather;~~market conditions;

$34 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 of2019 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~~higher income tax expense due to the recognition of additional AMT credits related to a revision in tax law ~~guidance.~~guidance in 2019 not recurring in 2020;

~~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~~$2 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;~~higher operations 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.

~~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) AFUDCmaintenance expenses related to an increase in ~~construction projects.~~employee benefits expense; and

~~Income Tax Expense~~

~~Income Tax Expense decreased by $4~~$1 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~~due to lower retail revenue primarily due to a decrease in ~~earnings before tax expense and the recognition of AMT credits in the first quarter of 2019~~usage related to ~~a revision~~unfavorable weather and business closures in ~~tax law guidance.~~response to the COVID-19 pandemic.

The decrease was partially offset by $2 million in higher LFCR revenues.

FACTORS AFFECTING RESULTS OF OPERATIONS

Several factors affect our current and future results of operations. The most significant factors are related to the potential economic impacts of the COVID-19 pandemic, regulatory matters, generation resource diversification, and weather patterns.

COVID-19 Pandemic Impacts

The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on certain developments, including: (i) the duration of the declared health emergencies; (ii) actions being taken by governmental authorities and regulators; (iii) the impact on our customers, employees, and vendors; and (iv) actions being taken by us to assist our customers through this crisis. These developments are all rapidly evolving and challenging to predict. Areas that we currently anticipate as likely to be materially impacted and which may have an effect on our results of operations, cash flows, and earnings are noted below.

Retail Sales

As a result of the closure of non-essential businesses, stay at home orders, and economic impacts related to the COVID-19 pandemic, energy usage by our commercial customers is expected to fall below average levels experienced in prior periods. This decrease is expected to last for the duration of the pandemic response and may continue beyond as a result of sustained economic impacts in our service territory. However, we may experience an increase in residential energy usage due to widespread adoption of work from home practices. Impacts to future results of operations are expected but cannot be estimated at this time.

Timing of Regulatory Decisions

Proceedings for our pending ACC rate case have been delayed as regulators and stakeholders experience work schedule disruptions related to the COVID-19 pandemic. Our pending FERC rate case may also experience a delay related to COVID-19 work schedule disruptions. Further rate case delays may occur due to continued work schedule disruptions.

Return on Investments

We experienced a decrease in the value of investments used to support certain post-employment benefits during the first three months of 2020 as a result of unfavorable market conditions arising from the COVID-19 pandemic. Large variations in the value of investments used to support certain post-employment benefits may continue due to volatility in equity and fixed-income markets.

Retail Customer Assistance

In March 2020, we suspended service disconnections and late fees for all customers until further notice to help customers affected by the COVID-19 pandemic. We are also offering customers flexible payment extensions and payment plans. Notwithstanding current economic conditions, we did not experience a material increase in uncollectible accounts during the first three months of 2020. We will continue to assess credit loss risk and may experience an increase in bad debt expense due to the COVID-19 pandemic.

Temporary Reduction to DSM Surcharge

In April 2020, we filed a request with the ACC to refund to customers approximately $8 million of over-collected DSM funds over a two-month period beginning in May 2020. The proposed refund would be in the form of a temporary reduction to the existing DSM surcharge. We believe the proposed accelerated refund will provide more timely financial assistance to our customers.

The ACC is expected to consider this proposal and various other issues related to the COVID-19 pandemic at upcoming proceedings, including the financial impacts of the pandemic on customers and utilities. We cannot predict the timing or outcome of these proceedings.

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~~2019 Annual Report on Form 10-K and new regulatory matters occurring in ~~2019.~~2020.

2019 ACC Rate Case

OnIn April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018, 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~~TEP's key ~~provisions~~proposals of the rate case, adjusted for rebuttal testimony filed in November 2019, include:

a ~~7.68%~~7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of ~~10.35%~~10.00% 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,~~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 the Sundt RICE ~~units at Sundt;~~Units;

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~~Hearings before an ALJ were held in January and February 2020, and are scheduled to resume in June 2020 to address the request for inclusion of cost recovery in rates for Gila River Unit 2 and the Sundt RICE Units. As a result of work schedule disruptions arising from the COVID-19 pandemic, the timing of when new rates will go into effect is uncertain.

We cannot predict the outcome of ~~this~~the proceeding.

2019 FERC Rate Case

~~On May 31,~~In 2019, ~~TEP filed a proposal with~~ the FERC ~~requesting~~issued an order approving TEP's proposed OATT revisions ~~to its OATT. The filing requests that the new rates be implemented by~~effective August 1, ~~2019.~~2019, subject to refund and further proceedings.

~~The key provisions~~Provisions of the ~~filing include:~~order include, but are not limited to:

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~~is intended to allow for a more timely recovery of transmission-related costs. If this request is approved, transmission ~~related costs. Based on the formula rate proposed, TEP anticipates an~~revenues would increase ofby approximately $7 million ~~over current annual transmission revenue.~~

~~On July 31, 2019,~~annually. As part of the order, the 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~~ All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. TEP had reserved $6 million as of March 31, 2020, and $4 million as of December 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~~wholesale revenues 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 Current Liabilities—Regulatory ~~and Other Assets—Regulatory Assets~~Liabilities on the Condensed Consolidated Balance Sheets.

~~TEP~~ We 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.proceeding.

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~~issued the ACC Refund ~~Order effective May 1, 2018.~~Order. The ~~refund~~ACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be ~~trued up~~trued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh ~~sales.~~sales for the calendar year. Any over or under collected amounts are deferred to a regulatory ~~asset~~liability or ~~liability~~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 refund amounts totaled $33 million in both 2019 and 2018. TEP filed an ~~application~~informational filing with the ACC to

establish ~~the 2019~~a 2020 customer refund of ~~$34~~$35 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%~~2020. The customer bill credit will account for 50% of the ~~2019 refund into a regulatory liability~~returned savings in 2020 and ~~50%~~through the completion 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.~~next rate case. TEP has proposed a TEAM to return the ~~refunds~~remaining deferred ~~in the regulatory liability account be returned to customers through the TEAM in the same year the 2019 Rate Case is completed.~~balance.

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 and 2020, the ACC ~~Staff issued proposed modifications to the ACC’s~~staff and two commissioners prepared different drafts of retail electric competition rules. The ACC ~~discussed~~is expected to discuss those draft rules ~~on July 30, 2019, as part of a scheduled workshop.~~during upcoming workshops, but such rules have not been officially proposed and no changes have been made. We anticipate that the ACC will hold additional workshops related to retail electric competition and other energy-related policies. 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.

Generation Resource Diversification

TEP’s long-term strategy is to shift to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. TEP's existing coal-fired generation fleet faces a number of uncertainties impacting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.

As of March 31, 2020, approximately 37% of our generation capacity was from coal-fired generation.

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

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~~retired the generation station in November 2019 and ~~begin~~began decommissioning activities. TEP expects the majority of decommissioning activities ~~thereafter. Navajo~~to be completed by 2024 with monitoring activities continuing through 2054. TEP is ~~expected to shut down on or before December 22, 2019. We are~~ currently recovering ~~Navajo's~~the capital and operating costs in base rates using a useful life ~~through 2030.~~of 2030 for Navajo. Due to the early retirement, ~~of Navajo, in the 2019 Rate Case we have~~TEP requested recovery of final retirement costs over a 10-year ~~period.~~period in the 2019 ACC Rate Case. As of ~~June 30, 2019,~~March 31, 2020, the net book value of Navajo was ~~$41~~$42 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~~2018, the Pima County Department of Environmental Quality ~~related~~approved TEP's air permit, which allowed TEP to ~~a generation modernization project at Sundt. Under the project, TEP will~~ place in service 10 natural gas RICE units at Sundt and required the retirement of Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 of Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 ACC Rate Case. As of March 31, 2020, the net book value of Sundt Units 1 and 2 was $25 million, with ~~a total nominal generation capacity~~estimated other related costs of ~~190 MW. The final permit was issued~~$1 million.

TEP placed in ~~December 2018. Construction is underway with~~service five of the RICE units ~~scheduled for commercial operation by~~in December 2019, and the ~~end of the first quarter of~~remaining five were placed in service in March 2020. ~~We have requested recovery of the~~The Sundt RICE ~~project costs in the 2019 Rate Case.~~

~~The RICE units will~~Units balance the variability of intermittent renewable energy ~~resources and will replace~~resources. The units replaced 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which ~~are~~were less efficient and ~~lack~~lacked the quick start, fast ramp capabilities of the Sundt RICE ~~units.~~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~~the 10 Sundt RICE Units over ~~a 10-year period~~the useful lives of the assets in the 2019 ACC Rate Case. AsThe total cost of ~~June 30, 2019,~~ the ~~net book value of~~ Sundt RICE Units ~~1 and 2~~project was ~~$27 million, with estimated other related costs of $1~~$178 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~~included a three-year option to purchase ~~Gila River Unit 2 (Tolling PPA).~~the unit. TEP ~~anticipates completing~~completed the purchase of Gila River Unit 2 in December 2019 for ~~approximately $164~~$165 million. The 550 MW of capacity, power, and ancillary services replaced coal-fired

generation lost due to early retirements. We ~~have~~ requested recovery of the Gila River Unit 2 purchase over the remaining useful life of the asset in the 2019 ACC Rate Case.

Executive Order

On May 1, 2020, the President of the United States of America signed an Executive Order, Securing the United States Bulk-Power System. We are currently evaluating the potential impacts of this Executive Order.

Production Tax Credits

Federal renewable electricity Production Tax Credits (PTC) are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law. Qualifying generating facilities are eligible for the credit for 10 years from the date the facilities are placed in service. The PTC rate is published annually by the IRS and was $0.025 per kWh produced and sold for 2019. TEP will ~~continue to pay a monthly demand charge consisting of: (i) a fixed capacity charge~~begin earning PTCs once Oso Grande begins producing and selling power.

Weather Patterns

Weather and other factors cause seasonal fluctuations in the sales 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 bypower. TEP's summer peaking load occurs during the third quarter of ~~2019 and be completed by December 2020. The wind project~~the year when cooling demand is ~~expected to qualify for~~higher, which results in higher revenue during such period. By contrast, lower sales of power occur during the ~~IRS renewable Production Tax Credit. The credit is expected to recover a minimum of $250 million~~first quarter of the ~~project's costs~~year, due to mild winter weather in our retail service territory. Seasonal fluctuations affect the ~~first 10 years and the remaining portion~~comparability 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~~our results of ~~a larger and more diverse pool of resources, more effectively integrate renewables, and enhance reliability through improved system utilization and responsiveness.~~

operations.

Interest Rates

See Part II, Item 7A in our ~~2018~~2019 Annual Report on Form 10-K and Part ~~II,~~I, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.

RESULTS OF OPERATIONS

Significant drivers of TEP's results of operations that do not have a significant impact on net income include:

•

Cost Recovery Mechanisms — TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, Renewable Energy Standard Tariff, and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on cost recovery mechanisms.


•	Short-Term Wholesale Sales — Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC cost recovery mechanism.


•	Springerville Units 3 and 4 — Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.

The following discussion provides the significant items that affected TEP's results of operations in the first three months of 2020 compared with the same period in 2019 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:



	Three Months Ended March 31,				Increase (Decrease)
(in millions)	2020		2019		Percent
Operating Revenues
Retail	$	192	$	202	(5.0	)%
Wholesale, Long-Term	7		9		(22.2	)%
Wholesale, Short-Term ⁽¹⁾	29		72		(59.7	)%
Transmission	7		8		(12.5	)%
Springerville Units 3 and 4 Participant Billings	20		20		—	%
Other	24		22		9.1	%
Total Operating Revenues	$	279	$	333	(16.2	)%


⁽¹⁾	Revenues associated with derivatives are primarily passed back to retail customers by offsetting the fuel and purchase power costs eligible for recovery through the PPFAC mechanism similar to short-term wholesale sales. As a result, revenues associated with derivatives are included in Wholesale, Short-Term in the table above.

TEP reported operating revenues of $279 million in the first three months of 2020 compared with $333 million in the same period for 2019. The decrease of $54 million, or 16%, was primarily due to:

$43 million in lower wholesale short-term sales primarily due to a decrease in (i) volumes driven by the expiration of a capacity sale contract in December 2019; and (ii) pricing as a result of unfavorable market conditions; and

$10 million in lower retail revenue primarily due to lower fuel and purchase power recoveries as a result of lower PPFAC rates.

The decrease was partially offset by a $2 million increase in other revenues primarily due to higher LFCR revenue.

The following table provides key statistics impacting operating revenues:



	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2020	2019	Percent
Electric Sales (kWh) ⁽¹⁾
Retail Sales	1,800	1,836	(2.0	)%
Wholesale, Long-Term	72	135	(46.7	)%
Wholesale, Short-Term	1,246	2,047	(39.1	)%
Total Electric Sales	3,118	4,018	(22.4	)%

Average Revenue Per kWh (Cents/kWh) ⁽²⁾
Retail	10.67	11.02	(3.2	)%
Wholesale, Long-Term	10.04	6.72	49.4	%
Wholesale, Short-Term	2.30	3.57	(35.6	)%

Total Retail Customers ⁽³⁾	431,691	426,756	1.2	%


⁽¹⁾	These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.


⁽²⁾	This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.


⁽³⁾	This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining), industrial (non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.

Operating Expenses

Fuel and Purchased Power Expense

TEP reported fuel and purchased power expense of $91 million in the first three months of 2020 compared with $140 million in the same period for 2019. The decrease of $49 million, or 35%, was primarily due to:

$26 million in lower fuel costs primarily due to a decrease in natural gas prices and a decrease in Coal and Gas-Fired Generation volumes;

$15 million in lower purchased power primarily due to a decrease in volume and the purchase of Gila River Unit 2; and

$7 million in lower PPFAC recoveries primarily due to changes in the PPFAC rate.

The following provides key statistics impacting fuel and purchase power:



	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2020	2019	Percent
Sources of Energy
Coal-Fired Generation	1,409	1,766	(20.2	)%
Gas-Fired Generation	1,476	1,832	(19.4	)%
Utility-Owned Renewable Generation	20	20	—	%
Total Generation	2,905	3,618	(19.7	)%
Purchased Power, Non-Renewable	170	420	(59.5	)%
Purchased Power, Renewable	151	144	4.9	%
Total Generation and Purchased Power ⁽¹⁾	3,226	4,182	(22.9	)%



(cents per kWh)
Average Fuel Cost of Generated Power ⁽²⁾
Coal	2.53	2.16	17.1	%
Natural Gas ⁽³⁾	1.80	2.75	(34.5	)%
Average Cost of Purchased Power ⁽⁴⁾
Purchased Power, Non-Renewable	2.59	4.08	(36.5	)%
Purchased Power, Renewable	9.31	9.25	0.6	%


⁽¹⁾	This number represents the kWh generated from TEP's generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.


⁽²⁾	This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation stations.


⁽³⁾	Includes realized gains and losses from hedging activity.


⁽⁴⁾	This metric represents the fuel cost as cents per kWh for renewable and non-renewable purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh) for each respective form of purchased power. Management uses this metric to compare and monitor the costs of renewable and non-renewable purchased power.

Operations and Maintenance Expense

TEP reported operations and maintenance expense of $87 million in the first three months of 2020 compared with $87 million in the same period for 2019, an increase of less than $1 million, or 1%. The increase was primarily due to $2 million in increased employee benefits expense. The increase was partially offset by $2 million in lower expenses related to Springerville Units 3 and 4 due to planned outages in 2019 not recurring in 2020.

Depreciation and Amortization Expense

Depreciation and amortization expense increased by $5 million, or 9%, in the first three months of 2020 compared with the same period in 2019 primarily due to an increase in asset base.

Other Income (Expense)

TEP reported other expense of $20 million in the first three months of 2020 compared with $14 million in the same period for 2019. The increase of $6 million, or 43%, was primarily due to a $10 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions.

The increase was partially offset by:

$2 million in lower finance lease interest expense due to the purchase of Gila River Unit 2 in December 2019;

$1 million increase in other income due to an increase in expected return on pension plan assets; and

$1 million in higher Allowance for Funds Used During Construction due to an increase in construction projects.

Income Tax Expense

TEP reported tax expense of $4 million in the first three months of 2020 compared with $2 million in the same period for 2019. The increase of $2 million, or 100%, was primarily due to:

$2 million in lower tax credits related to AMT credits recognized in the first quarter of 2019 not recurring in 2020; and

$1 million in higher plant flow through and EDIT amortization.

The increase was partially offset by $2 million in lower tax expense due to a decrease in taxable earnings.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

~~Cash~~The COVID-19 pandemic has negatively impacted the global economy and created significant volatility and disruption of financial markets. An extended period of economic disruption could negatively affect our business and financial condition, and access to sources of liquidity. In addition, cash flows may vary during the year with cash flows from operations typically 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~~fund our business activities. ~~We believe that~~Based on our expectations, including possible impacts of COVID-19 on sales, accounts receivable collections, and capital spending, 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.~~anticipate the need for external financing in the third or fourth quarter of 2020. 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~~bank and capital markets.

Available Liquidity


(in millions)	June 30, 2019		March 31, 2020
Cash and Cash Equivalents	$	70	$	12
Amount Available under Revolving Credit Facility ⁽¹⁾	250
Amount Available under Revolving Credit Agreement ⁽¹⁾			153
Total Liquidity	$	320	$	165


⁽¹⁾	~~TEP's revolving credit facility~~The 2015 Credit Agreement 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~~2019 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)		Three Months Ended March 31,						Increase (Decrease)
(in millions)	2019			2018			Percent		2020			2019			Percent
Operating Activities	$	163		$	198		(17.7	)%	$	91		$	82		11.0	%
Investing Activities	(221		)	(193		)	14.5	%	(373		)	(113		)	230.1	%
Financing Activities	(11		)	(38		)	(71.1	)%	284			(11		)	*
Net Increase (Decrease)	(69		)	(33		)	109.1	%	2			(42		)	(104.8	)%
Beginning of Period	153			50			206.0	%	28			153			(81.7	)%
End of Period ⁽¹⁾	$	84		$	17		394.1	%	$	30		$	111		(73.0	)%

* Not meaningful


⁽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~~three months of ~~2019,~~2020, net cash flows from operating activities ~~decreased~~increased by ~~$35~~$9 million compared with the same period in ~~2018.~~2019. The ~~decrease~~increase was primarily due to: (i) ~~lower retail sales as~~$10 million of collateral posted to a ~~result of unfavorable weather;~~counterparty for a credit enhancement in 2019 not occurring in 2020; and (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~~collections. The increase was partially offset by lower retail revenue primarily due to: (i) lower fuel and ~~payments.~~purchase power recoveries as a result of lower PPFAC rates; and (ii) lower customer usage due to unfavorable weather and impacts of the COVID-19 pandemic.

Investing Activities

In the first ~~six~~three months of ~~2019,~~2020, net cash flows used for investing activities increased by ~~$28~~$260 million compared with the same period in ~~2018~~2019 primarily due to ~~an increase in cash paid~~a payment of $226 million for ~~capital expenditures in 2019.~~

the Oso Grande project under the build-transfer agreement.

Financing Activities

In the first ~~six~~three months of ~~2019,~~2020, net cash flows ~~used for~~from financing activities ~~decreased~~increased by ~~$27~~$295 million compared with the same period in ~~2018~~2019 primarily due ~~to a decrease~~to: (i) an increase in ~~repayments,~~equity contributions from UNS Energy; and (ii) higher proceeds from credit facility borrowings, 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.repayments.

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~~March 31, 2020, TEP had no short-term ~~investments included highly-rated and liquid money market funds and insured cash sweep accounts.~~investments.

Access to ~~Revolving~~ Credit ~~Facility~~Agreements

We have access to working capital through ~~a revolving~~our credit ~~agreement with lenders. TEP expects that amounts~~agreements.

Amounts borrowed from the 2019 Credit Agreement were used (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. As of March 31, 2020, there was no amount available under the ~~credit facility~~2019 Credit Agreement. In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the 2019 Credit Agreement's outstanding term loan and terminate such agreement.

Amounts borrowed from the 2015 Credit Agreement will be used for working capital and other general corporate purposes and ~~that~~ LOCs will be issued from time to time to support energy procurement, hedging transactions, and ~~hedging transactions.~~other business activities. As of ~~June 30, 2019,~~

March 31, 2020, there was ~~$250~~$153 million available under the ~~revolving credit commitments and~~2015 Credit Agreement. As of May 5, 2020, there was $238 million available under the ~~LOC facility.~~2015 Credit Agreement.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our ~~2018~~2019 Annual Report on Form 10-K for additional information regarding TEP's credit ~~facility~~agreements.

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.

On February 14, 2020, TEP filed a financing application with the ACC. The application requests extending and expanding the existing financing authority by: (i) extending authority from December 2020 to December 2025; (ii) increasing the outstanding long-term debt limitation from $2.2 billion to $2.9 billion; (iii) allowing parent equity contributions of up to $700 million; and (iv) continuing the interest rate hedging authority.

In April 2020, we issued and sold $350 million aggregate principal amount of senior unsecured notes to repay: (i) $225 million of outstanding borrowings under our 2019 Credit Agreement, which we terminated; and (ii) outstanding borrowings under our 2015 Credit Agreement, and intend to use the remaining balance for general corporate purposes.

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,~~March 31, 2020, 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~~depend 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~~Certain of TEP's debt agreements contain 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,~~March 31, 2020, 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 equity contributions of $150 million from UNS Energy in the first three months of 2020 and received no equity contributions in the ~~second quarter or~~ first ~~six~~three months of ~~2019~~2019. On April 27, 2020, UNS Energy approved an equity contribution up to $100 million to TEP to be paid on or ~~2018.~~

before June 30, 2020.

Dividends Paid to Parent

TEP did not declare or pay dividends to UNS Energy in the ~~second quarter or~~ first ~~six~~three months of ~~2019~~2020 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 based on changes inin: (i) contract ~~values, changes in TEP’s~~values; (ii) our credit ~~ratings,~~ratings; or (iii) material changes in ~~TEP’s~~our creditworthiness. As of ~~June 30, 2019,~~March 31, 2020, TEP had posted no cash or LOCs as credit enhancements with its ~~counterparties.~~counterparties related to our wholesale marketing or risk management activities. As of May 5, 2020, there was no collateral posted.

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. TEP is prioritizing capital projects to mitigate supply chain risk and other potential impacts of the COVID-19 pandemic and ensure we continue providing safe and reliable service while supporting public health. As a result, we expect to have reductions in forecasted capital expenditures due to prioritizing certain projects and postponing others. In the first ~~six~~three months of ~~2019,~~2020, there ~~have been~~were 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~~three months of ~~2019,~~2020, there ~~have been~~were no material changes outside the ordinary course of business to contractual obligations as reported in our ~~2018~~2019 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.10-K.

Off-Balance Sheet Arrangements

Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our ~~2018~~2019 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~~TEP did not make any U.S. federal or Arizona State income tax payments 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~~first three months of 2020 due 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~~existing net operating loss and tax credit carryforwards ~~that are used to offset future taxable income.As a result,~~in those jurisdictions. Based on our remaining tax carryforward balances, 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~~anticipate making federal or state income tax payments of a material nature for the next several years.

Under the TCJA, existing AMT credit carryforwards ~~will~~could be refunded ~~if not~~or used to offset U.S. federal income tax ~~liabilities.~~liabilities through our 2021 tax year. In response to the COVID-19 pandemic, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was signed into law March 27, 2020. Along with other significant provisions, the CARES Act further accelerated the recovery of AMT credits by allowing corporations to immediately claim refunds of all unused carryforward balances. As a result, TEP ~~received no refunds in the first six months of 2019 and~~ expects to receive ~~refunds of~~ approximately $14 million in ~~2019, $7 million~~AMT credit refunds in ~~2020, and $3 million in 2021 and 2022.~~2020.

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.

Payroll Tax

The CARES Act also allows employers to defer the deposit and payment of the employer's share of social security taxes. TEP is deferring the deposit of the employer's portion of social security tax through the end of 2020. We expect the deferred deposits to be approximately $7 million, and be paid to the IRS in equal payments in 2021 and 2022.

Environmental Matters

The ~~EPA~~Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon dioxide (CO₂), particulate matter, mercury and other by-products produced by generation facilities. 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

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. See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the Broadway-Pantano site.

Regional Haze Regulations

The ~~Environmental Protection Agency's (EPA)~~EPA's 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)~~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 Sundt Unit 3 and Springerville Units 1 and ~~Sundt~~2 had been selected for potential emissions controls evaluation. ~~The~~

TEP conducted the potential emissions controls evaluation, commonly referred to as the four factor analysis, for both facilities. These evaluations ~~are to be performed for each facility and~~were submitted to the ADEQ ~~by December 2019.~~

in March 2020 for the agency's use in developing the revised SIP. TEP will continue to work with the agency to determine compliance strategies as needed, however, TEP cannot predict the outcome of these matters at this time.

The ADEQ ~~to prepare and~~must submit the ~~evaluations~~revised SIP to the EPA for approval by ~~the required deadline.~~July 2021. Based on current Regional Haze requirement time-frames, TEP anticipates that ~~impacts,~~compliance strategies, if any, ~~to the facilities~~ will likely ~~occur~~be required to be implemented 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~~CO₂ emissions from existing and new fossil fuel-based generation facilities. The CPP ~~established~~establishes state-level ~~CO2~~CO₂ emission rates and mass-based goals that apply to fossil fuel-based generation. The plan ~~targeted CO2~~targets 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~~generation facilities is defined as ~~heat-rate (efficiency) improvements~~Heat-Rate Improvements (HRI) 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~~The ADEQ began the stakeholder process in November 2019 and notified subject facilities that HRI analysis would be due to the agency by December 2020. We are in in the process of conducting the HRI analysis for Springerville Units 1 and 2, and therefore cannot predict the outcome of these matters at this time. However, we do not anticipate a material impact to Springerville Units 1 and 2 at this time.

Effective September 2019, 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~~Legal challenges ~~which~~to the rule could delay the effectiveness and implementation of the new rule. On March 23, 2020, the U.S. Court of Appeals for the D.C. Circuit Court postponed the briefing schedule, pending further order of the court, in judicial challenges to the ACE rule in light of the COVID-19 pandemic.

Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring disposal of coal ash and other ~~coal combustion residuals~~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$3 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. In August 2019, the EPA issued the Phase 2 rule revision proposal. TEP does not anticipate a

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~~anticipated proposed rule ~~in 2019. The second phase is also anticipated to be finalized in 2019.~~revisions.

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~~three months ended ~~June 30, 2019,~~March 31, 2020, 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~~2019 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.

The COVID-19 pandemic has had a negative impact on the global economy and financial markets. There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our ~~2018~~2019 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~~March 31, 2020. There was no change in TEP’s internal control over financial reporting during the quarter ended ~~June 30, 2019,~~March 31, 2020, that ~~has~~ materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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~~2019 Annual Report on 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~~2019 Annual Report on Form ~~10-K.~~10-K, except as noted below:

The widespread outbreak of an illness or any other communicable disease, or any other public health crisis, including the COVID-19 pandemic, could adversely affect our business, results of operations and financial condition.

TEP could be negatively impacted by the widespread outbreak of an illness or any other communicable disease, or any other public health crisis that results in economic and trade disruptions, including the disruption of global supply chains. In March 2020, the World Health Organization declared COVID-19 a pandemic. The COVID-19 pandemic has negatively impacted the global, national, and our local economy, disrupted global supply chains, and created significant volatility and disruption of financial markets. The COVID-19 pandemic has resulted in closure of school and certain business facilities, travel restrictions, disruptions to supply chains, and disruptions to workplaces as employees and contractors cease to be available to perform critical work functions. The extent of the impact of the COVID-19 pandemic on TEP’s operational and financial performance, including the ability to execute business strategies and initiatives in the expected time frame, the ability to obtain external financing, and the timing of regulatory actions, will depend on future developments, including the duration and spread of the pandemic and related restrictions on travel and transports, all of which are uncertain and cannot be predicted at this time. An extended period of global supply chain and economic disruption could materially affect TEP’s business, results of operations, access to sources of liquidity, and financial condition.

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Table of Contents

ITEM 6. EXHIBITS



EXHIBIT INDEX
Exhibit No.		Description
31(a)		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by David G. Hutchens

31(b)		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, 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,~~ March 31, 2020, formatted in Inline XBRL and contained in Exhibit 101



*	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.

3637

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~~May 5, 2020	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)

3738



	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



(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



(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



(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



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



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



(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	)%