Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 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 July 29, 2020.

Table of Contents



Definitions	iii
Forward-Looking Information	v
PART I

Item 1. Financial Statements
Condensed Consolidated Statements of Income	1
Condensed Consolidated Statements of Comprehensive Income	2
Condensed Consolidated Statements of Cash Flows	3
Condensed Consolidated Balance Sheets	4
Condensed Consolidated Statements of Changes in Stockholder's Equity	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Critical Accounting Policies and Estimates	36
New Accounting Standards Issued and Not Yet Adopted	36
Item 3. Quantitative and Qualitative Disclosures about Market Risk	37
Item 4. Controls and Procedures	37

PART II

Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 6. Exhibits	39
Signatures	40

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		In April 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018
2019 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
2020 IRP		TEP's 2020 Integrated Resource Plan filed with the ACC in June 2020, which outlines TEP's energy portfolio over the next 15 years
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 customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018
ADEQ		Arizona Department of Environmental Quality
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMT		Alternative Minimum Tax
COVID-19		Coronavirus Disease 2019
DG		Distributed Generation
DSM		Demand Side Management
EDIT		Excess Deferred Income Taxes
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
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
Summer Moratorium		Emergency rules first enacted by the ACC in 2019 that suspend service disconnections and late fees for electric residential customers who otherwise would be eligible for service disconnection during the period from June 1 through October 15
TCA		Transmission Cost Adjustor
TCJA		Tax Cuts and Jobs Act
TEAM		Tax Expense Adjustor Mechanism

iii

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
Oso Grande		A 250 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
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), 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 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 final outcome of the FERC order effective August 2019, subject to refund, approving 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 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 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; the impact of the TCJA on our financial condition and results of operations, including the assumptions we make relating thereto; and the implementation of our 2020 IRP.

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,
	2020			2019			2020			2019
Operating Revenues	$	339,705		$	326,091		$	618,261		$	659,094

Operating Expenses
Fuel	62,697			75,441			125,996			164,859
Purchased Power	28,833			27,345			47,151			60,195
Transmission and Other PPFAC Recoverable Costs	12,005			12,094			22,600			24,019
Increase (Decrease) to Reflect PPFAC Recovery Treatment	6,378			(10,918		)	5,196			(4,713		)
Total Fuel and Purchased Power	109,913			103,962			200,943			244,360
Operations and Maintenance	84,032			92,045			171,487			178,633
Depreciation	47,123			41,427			93,622			82,744
Amortization	7,042			7,397			13,998			15,014
Taxes Other Than Income Taxes	14,643			14,120			29,552			28,321
Total Operating Expenses	262,753			258,951			509,602			549,072

Operating Income	76,952			67,140			108,659			110,022

Other Income (Expense)
Interest Expense	(22,572		)	(22,144		)	(43,053		)	(44,275		)
Allowance For Borrowed Funds	2,013			1,303			4,895			2,577
Allowance For Equity Funds	7,189			3,398			10,223			6,721
Unrealized Gains (Losses) on Investments	3,276			934			(3,151		)	4,014
Other, Net	1,339			(92		)	2,192			116
Total Other Income (Expense)	(8,755		)	(16,601		)	(28,894		)	(30,847		)

Income Before Income Tax Expense	68,197			50,539			79,765			79,175
Income Tax Expense	10,707			8,476			14,357			10,917
Net Income	$	57,490		$	42,063		$	65,408		$	68,258

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,
	2020		2019		2020		2019
Comprehensive Income
Net Income	$	57,490	$	42,063	$	65,408	$	68,258
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $0 and $8	—		24
Net of Income Tax Expense of $0 and $17					—		52
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $45 and $22	135		66
Net of Income Tax Expense of $90 and $44					270		132
Total Other Comprehensive Income, Net of Tax	135		90		270		184
Total Comprehensive Income	$	57,625	$	42,153	$	65,678	$	68,442

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,
	2020			2019
Cash Flows from Operating Activities
Net Income	$	65,408		$	68,258
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	93,622			82,744
Amortization Expense	13,998			15,014
Amortization of Debt Issuance Costs	1,280			1,153
Use of Renewable Energy Credits for Compliance	21,664			18,624
Deferred Income Taxes	19,866			14,244
Pension and Other Postretirement Benefits Expense	7,442			8,881
Pension and Other Postretirement Benefits Funding	(4,955		)	(6,431		)
Allowance for Equity Funds Used During Construction	(10,223		)	(6,721		)
Regulatory Deferral, ACC Refund Order	8,817			3,156
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(11,386		)	5,910
Materials, Supplies, and Fuel Inventory	3,847			(4,689		)
Regulatory Assets	(1,500		)	(151		)
Other Current Assets	2,121			1,766
Accounts Payable and Accrued Charges	(20,317		)	(32,061		)
Income Taxes Receivable, Net	(7,154		)	(3,326		)
Regulatory Liabilities	3,213			(4,507		)
Other, Net	2,661			969
Net Cash Flows—Operating Activities	188,404			162,833
Cash Flows from Investing Activities
Capital Expenditures	(473,881		)	(199,791		)
Purchase Intangibles, Renewable Energy Credits	(25,746		)	(24,793		)
Purchase, Other Investments	(8,556		)	—
Contributions in Aid of Construction	2,329			3,932
Net Cash Flows—Investing Activities	(505,854		)	(220,652		)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	105,000			—
Repayments of Borrowings, Revolving Credit Facility	(105,000		)	—
Proceeds from Borrowings, Term Loan	60,000			—
Repayments of Borrowings, Term Loan	(225,000		)	—
Proceeds from Issuance, Long-Term Debt—Net of Discount	346,983			—
Payments of Finance Lease Obligations	(11,535		)	(10,889		)
Contribution from Parent	200,000			—
Other, Net	(2,632		)	(166		)
Net Cash Flows—Financing Activities	367,816			(11,055		)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	50,366			(68,874		)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	28,472			152,747
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	78,838		$	83,873

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, 2020			December 31, 2019
ASSETS
Utility Plant
Plant in Service	$	6,902,038		$	6,663,912
Utility Plant Under Finance Leases	151,467			151,467
Construction Work in Progress	483,450			303,488
Total Utility Plant	7,536,955			7,118,867
Accumulated Depreciation and Amortization	(2,559,434		)	(2,506,686		)
Accumulated Amortization of Finance Lease Assets	(82,160		)	(77,285		)
Total Utility Plant, Net	4,895,361			4,534,896

Investments and Other Property	67,049			62,136

Current Assets
Cash and Cash Equivalents	60,895			9,762
Accounts Receivable (Net of Allowance for Credit Losses of $6,679 and $5,716)	166,855			154,847
Fuel Inventory	24,672			23,731
Materials and Supplies	116,755			121,542
Regulatory Assets	123,848			138,412
Derivative Instruments	8,771			3,596
Other	26,839			21,416
Total Current Assets	528,635			473,306
Regulatory and Other Assets
Regulatory Assets	322,072			326,860
Derivative Instruments	3,872			2,763
Other	92,347			89,196
Total Regulatory and Other Assets	418,291			418,819
Total Assets	$	5,909,336		$	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, 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, 2020 and December 31, 2019)	$	1,596,539		$	1,396,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	661,200			595,792
Accumulated Other Comprehensive Loss	(7,501		)	(7,771		)
Total Common Stock Equity	2,243,881			1,978,203
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2020 and December 31, 2019)	—			—
Finance Lease Obligations	—			67,316
Long-Term Debt, Net	1,865,995			1,522,087
Total Capitalization	4,109,876			3,567,606
Current Liabilities
Current Maturities of Long-Term Debt, Net	80,383			80,330
Borrowings Under Credit Agreements, Net	—			165,000
Finance Lease Obligations	72,868			17,086
Accounts Payable	108,376			136,465
Accrued Taxes Other than Income Taxes	48,220			42,741
Accrued Employee Expenses	28,520			32,567
Accrued Interest	17,470			16,700
Regulatory Liabilities	100,190			96,017
Customer Deposits	20,871			24,568
Derivative Instruments	14,059			27,615
Other	26,420			23,678
Total Current Liabilities	517,377			662,767
Regulatory and Other Liabilities
Deferred Income Taxes, Net	459,920			432,484
Regulatory Liabilities	466,261			477,495
Pension and Other Postretirement Benefits	132,086			133,452
Derivative Instruments	52,099			48,697
Other	171,717			166,656
Total Regulatory and Other Liabilities	1,282,083			1,258,784

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	5,909,336		$	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, 2019	$	1,346,539	$	(6,357	)	$	510,472	$	(4,620	)	$	1,846,034
Net Income						42,063					42,063
Other Comprehensive Income, Net of Tax								90			90
Balances as of June 30, 2019	$	1,346,539	$	(6,357	)	$	552,535	$	(4,530	)	$	1,888,187



Balances as of March 31, 2020	$	1,546,539	$	(6,357	)	$	603,710	$	(7,636	)	$	2,136,256
Net Income						57,490					57,490
Other Comprehensive Income, Net of Tax								135			135
Contribution from Parent	50,000										50,000
Balances as of June 30, 2020	$	1,596,539	$	(6,357	)	$	661,200	$	(7,501	)	$	2,243,881



	Six Months Ended
	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						68,258					68,258
Other Comprehensive Income, Net of Tax								184			184
Balances as of June 30, 2019	$	1,346,539	$	(6,357	)	$	552,535	$	(4,530	)	$	1,888,187



Balances as of December 31, 2019	$	1,396,539	$	(6,357	)	$	595,792	$	(7,771	)	$	1,978,203
Net Income						65,408					65,408
Other Comprehensive Income, Net of Tax								270			270
Contribution from Parent	200,000										200,000
Balances as of June 30, 2020	$	1,596,539	$	(6,357	)	$	661,200	$	(7,501	)	$	2,243,881

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

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 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 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 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			As Filed		Amount Reclassified			As Reclassified
(in thousands)	Three Months Ended June 30, 2019								Six Months Ended June 30, 2019
Other Income (Expense)
Other, Net	$	842	$	(934	)	$	(92	)	$	4,130	$	(4,014	)	$	116
Unrealized Gains (Losses) on Investments	—		934			934			—		4,014			4,014

Variable Interest Entities

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

Table of Contents

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:



	June 30,
(in millions)	2020		2019
Cash and Cash Equivalents	$	61	$	70
Restricted Cash included in:
Investments and Other Property	16		13
Current Assets—Other	2		1
Total Cash, Cash Equivalents, and Restricted Cash	$	79	$	84

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, 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.

Credit Losses

TEP adopted accounting guidance that requires entities to incorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. See Note 4 for additional disclosure about TEP's allowance for 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 rates and services for electric transmission and wholesale power sales in interstate commerce.

2019 ACC RATE CASE

In April 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018.

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


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


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

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•	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 purchase of Gila River Unit 2 and the installation of the Sundt RICE Units;


•	a TEAM 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 during the first six months of 2020. Parties to the rate case will file post-hearing briefs in July and August 2020. 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

In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings.

Provisions of the 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 is intended to allow for a more timely recovery of transmission related costs. As part of the order, the FERC 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 $9 million as of June 30, 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.

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 customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018 (ACC Refund Order). The 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 June 30,						Six Months Ended June 30,
(in millions)	2020			2019			2020			2019
Beginning of Period	$	—		$	3		$	—		$	4
ACC Refund (Reduction in Operating Revenues)	(9		)	(9		)	(16		)	(16		)
Amount Returned to Customers through Bill Credits	5			6			8			10
Regulatory Deferral	5			1			9			3
End of Period	$	1		$	1		$	1		$	1

Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. TEP filed an informational filing with the ACC to establish a 2020 customer refund of $35 million. The refund will be returned to customers

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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 $17 million as of June 30, 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 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,
(in millions)	2020			2019			2020			2019
Beginning of Period	$	36		$	(22	)	$	36		$	(17	)
Deferred Fuel and Purchased Power Costs ⁽¹⁾	67			75			115			128
PPFAC and Base Power Recoveries ⁽²⁾	(75		)	(62		)	(123		)	(120		)
End of Period	$	28		$	(9	)	$	28		$	(9	)


⁽¹⁾	Includes costs eligible for recovery through the PPFAC and base power rates.


⁽²⁾	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, which went into effect on June 1, 2020.

Renewable Energy Standard

The ACC’s Renewable Energy Standard (RES) requires 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 10% of retail electric sales, which will increase annually until renewable retail sales represent at least 15% by 2025. DG 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 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million. The recovery funds: (i) 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 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 2020 and 2019 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.

In 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, 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. In June 2020, TEP filed its 2021 energy efficiency implementation plan with a budget of approximately $23 million. TEP cannot predict the outcome of the proceeding.

TEP filed a request with the ACC in April 2020 to refund to customers approximately $8 million of over-collected DSM funds as a result of the COVID-19 pandemic. In May 2020, the ACC approved the request and TEP returned the funds in the form of customer bill credits over the June 2020 billing cycle.

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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 amounts are verifiable regardless of when the lost retail kWh sales 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.

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



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2020		2019		2020		2019
LFCR Revenues	$	10	$	6	$	22	$	16

REGULATORY ASSETS AND LIABILITIES

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



($ in millions)	Remaining Recovery Period (years)	June 30, 2020		December 31, 2019
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	131	$	135
Early Generation Retirement Costs	Various	64		68
Derivatives (Note 9)	10	59		72
Lost Fixed Cost Recovery	2	57		46
Income Taxes Recoverable through Future Rates ⁽¹⁾	Various	33		38
Under Recovered Purchased Energy Costs	1	28		36
Property Tax Deferrals ⁽²⁾	1	25		24
Final Mine Reclamation and Retiree Healthcare Costs ⁽³⁾	9	22		19
Springerville Unit 1 Leasehold Improvements⁽⁴⁾	3	8		9
Other Regulatory Assets	Various	19		18
Total Regulatory Assets		446		465
Less Current Portion	1	124		138
Total Non-Current Regulatory Assets		$	322	$	327



Regulatory Liabilities
Income Taxes Payable through Future Rates ⁽¹⁾	Various	$	315	$	327
Net Cost of Removal ⁽⁵⁾	Various	156		164
Renewable Energy Standard	Various	60		59
Deferred Investment Tax Credits ⁽⁶⁾	Various	2		3
Other Regulatory Liabilities	Various	33		20
Total Regulatory Liabilities		566		573
Less Current Portion	1	100		96
Total Non-Current Regulatory Liabilities		$	466	$	477


⁽¹⁾	Amortized over the lives of the assets.

⁽²⁾

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

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⁽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 be funded by TEP through 2028.


⁽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.


⁽⁵⁾	Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.


⁽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, 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 five natural gas RICE units at Sundt in December 2019 and an additional five units in March 2020. There was $183 million as of June 30, 2020, and $82 million, as of December 31, 2019, 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,
(in millions)	2020		2019		2020		2019
Retail	$	265	$	236	$	457	$	438
Wholesale ⁽¹⁾	30		43		66		127
Other Services	23		30		47		54
Revenues from Contracts with Customers	318		309		570		619
Alternative Revenues	10		6		24		18
Other	12		11		24		22
Total Operating Revenues ⁽²⁾	$	340	$	326	$	618	$	659


⁽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.


⁽²⁾	Calculated on rounded data and may not correspond exactly to TEP's Operating Revenues reported on the Condensed Consolidated Statements of Income.

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NOTE 4. ACCOUNTS RECEIVABLE

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



(in millions)	June 30, 2020			December 31, 2019
Retail	$	76		$	61
Retail, Unbilled	62			42
Retail, Allowance for Credit Losses	(7		)	(6		)
Wholesale⁽¹⁾	19			31
Due from Affiliates (Note 5)	6			8
Other	11			19
Accounts Receivable	$	167		$	155


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

ALLOWANCE FOR CREDIT LOSSES

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 June 30, 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			Six Months Ended
(in millions)	June 30, 2020			June 30, 2020
Beginning of Period	$	(6	)	$	(6	)
Credit Loss Expense	(1		)	(2		)
Write-offs	—			1
End of Period	$	(7	)	$	(7	)

Service Disconnection Moratoriums

In 2019, the ACC enacted emergency rules that suspended service disconnections and late fees for electric residential customers who would have otherwise been eligible for service disconnection during the period from June 1 through October 15 (Summer Moratorium). The emergency rules will remain in effect until the ACC permanently adopts new rules regarding electric service disconnections. In addition, in March 2020 TEP voluntarily suspended service disconnections and late fees for all customers who would have otherwise been eligible for service disconnection to help customers affected by the COVID-19 pandemic. As of June 1, 2020, the Summer Moratorium became effective for electric residential customers eligible for service disconnection.

As a result of the service disconnection moratoriums, in June 2020 TEP increased its bad debt reserve rate and estimated the total impact on operating expenses to be approximately $2 million through the end of 2020. The change to the bad debt reserve rate did not have a significant impact on operating expenses in the second quarter of 2020. TEP will continue monitoring collection activity and adjust the bad debt reserve rate as needed.

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NOTE 5. RELATED PARTY TRANSACTIONS

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

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



(in millions)	June 30, 2020		December 31, 2019
Receivables from Related Parties
UNS Electric	$	4	$	6
UNS Gas	2		2
Total Due from Related Parties	$	6	$	8

Payables to Related Parties
SES	$	2	$	2
UNS Electric	—		1
UNS Energy	1		1
Total Due to Related Parties	$	3	$	4

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



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2020		2019		2020		2019
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric ⁽¹⁾	$	2	$	2	$	4	$	3
Control Area Services, UNS Electric ⁽²⁾	1		1		2		2
Common Costs, UNS Energy Affiliates ⁽³⁾	4		5		9		10

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


⁽¹⁾	TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable 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 million for the three and six months ended June 30, 2020 and 2019, respectively.


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

DIVIDENDS PAID TO PARENT

On July 23, 2020, TEP declared a $38 million dividend to UNS Energy, which was paid July 27, 2020.

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NOTE 6. DEBT AND CREDIT AGREEMENTS

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% senior unsecured notes due June 2050. TEP may call the debt prior to December 15, 2049, with a make-whole premium plus accrued interest. After December 15, 2049, TEP may call the debt at par plus accrued interest. TEP used the net proceeds from the sale to repay amounts outstanding under its credit agreements and for general corporate purposes.

CREDIT AGREEMENTS

2019 Credit Agreement

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



	Capacity		Borrowed ⁽¹⁾		Available		Weighted Average Interest Rate		Pricing ⁽²⁾
(in millions)	June 30, 2020
Term Loan	$	225	$	225	$	—	—	%	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 table presents components of TEP's unsecured 2015 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:



	Capacity		Sub-Limit LOC		Borrowed ⁽¹⁾		Available		Weighted Average Interest Rate		Pricing ⁽²⁾
(in millions)	June 30, 2020
Revolver and LOC	$	250	$	50	$	12	$	238	—	%	LIBOR + 1.000%	or ABR + 0.00%


⁽¹⁾	Includes $12 million in LOCs issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement.


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

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NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2019 Annual Report on Form 10-K.

CONTINGENCIES

Legal Matters

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.

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. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP defers these 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.

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 $56 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 $39 million as of June 30, 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 San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of June 30, 2020, there have been no such payment defaults under any of the participation agreements. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046.

The Navajo participation agreement expired in 2019, 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 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

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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.

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)	2020			2019			2020			2019
Service Cost	$	4		$	3		$	1		$	1
Non-Service Cost ⁽¹⁾
Interest Cost	4			5			1			1
Expected Return on Plan Assets	(8		)	(7		)	(1		)	—
Amortization of Net Loss	2			2			—			—
Net Periodic Benefit Cost	$	2		$	3		$	1		$	2



	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2020			2019			2020			2019
Service Cost	$	8		$	6		$	2		$	2
Non-Service Cost⁽¹⁾
Interest Cost	8			9			1			1
Expected Return on Plan Assets	(15		)	(13		)	(1		)	—
Amortization of Net Loss	4			4			—			—
Net Periodic Benefit Cost	$	5		$	6		$	2		$	3


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

NOTE 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.

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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)	June 30, 2020
Assets
Restricted Cash ⁽¹⁾	$	18	$	—		$	18
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		8			8
Energy Derivative Contracts, No Regulatory Recovery ⁽²⁾	—		5			5
Total Assets	18		13			31
Liabilities
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		(66		)	(66		)
Total Liabilities	—		(66		)	(66		)
Total Assets (Liabilities), Net	$	18	$	(53	)	$	(35	)



(in millions)	December 31, 2019
Assets
Restricted Cash ⁽¹⁾	$	18	$	—		$	18
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		3			3
Energy Derivative Contracts, No Regulatory Recovery ⁽²⁾	—		3			3
Total Assets	18		6			24
Liabilities
Energy Derivative Contracts, Regulatory Recovery ⁽²⁾	—		(76		)	(76		)
Total Liabilities	—		(76		)	(76		)
Total Assets (Liabilities), Net	$	18	$	(70	)	$	(52	)


⁽¹⁾	Restricted Cash represents amounts held in money market funds, which approximates fair market value. 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 and forward purchased power and sales contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:



	Gross Amount Recognized in the Balance Sheets			Gross Amount Not Offset in the Balance Sheets					Net Amount
	Gross Amount Recognized in the Balance Sheets			Counterparty Netting of Energy Contracts			Cash Collateral Received/Posted		Net Amount
(in millions)	June 30, 2020
Derivative Assets
Energy Derivative Contracts	$	13		$	8		$	—	$	5
Derivative Liabilities
Energy Derivative Contracts	(66		)	(8		)	—		(58		)



(in millions)	December 31, 2019
Derivative Assets
Energy Derivative Contracts	$	6		$	4		$	—		$	2
Derivative Liabilities
Energy Derivative Contracts	(76		)	(4		)	(2		)	(70		)

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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.

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. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.

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

The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.

Energy Derivative Contracts, Regulatory Recovery

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



	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2020		2019			2020		2019
Unrealized Net Gain (Loss)	$	6	$	(11	)	$	15	$	(20	)

Energy Derivative Contracts, No Regulatory Recovery

TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income:



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2020		2019		2020		2019
Operating Revenues	$	4	$	5	$	5	$	5

Derivative Volumes

As of June 30, 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, 2020	December 31, 2019
Power Contracts GWh	5,474	4,740
Gas Contracts BBtu	110,461	122,779

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Level 3 Fair Value Measurements

As of June 30, 2020, TEP did not have any Level 3 asset or liability 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:



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

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

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 due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in counterparties' assessment of TEP's credit strength. In the event that such credit events were to occur, 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 $79 million as of June 30, 2020, compared with $100 million as of December 31, 2019. As of June 30, 2020, TEP had no collateral posted related to energy procurement or hedging activities. If the credit risk contingent features were triggered on June 30, 2020, TEP would have been required to post an additional $79 million of collateral of which $15 million relates to outstanding net payable balances for settled positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of 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 net carrying value and estimated fair value of TEP's long-term debt:



	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)	Fair Value Hierarchy	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,946	$	1,602	$	2,202	$	1,755

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

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


•	outlook and strategies;


•	factors affecting results of operations;


•	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.

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 anticipate, see Forward-Looking Information at the front of this report and Risk Factors in Part 1, Item 1A of our 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 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 our transition 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. In June 2020, we filed our 2020 IRP with the ACC. The 2020 IRP provides details on our long-term proposed strategy to eliminate the use of coal-fired generation over the next 12 years as part of our goal to reduce carbon emissions 80% compared to levels in 2005 by 2035. This resource strategy may be impacted by various federal and state energy policies currently under consideration.


•	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.

CURRENT ECONOMIC CONDITIONS—COVID-19

In March 2020, the World Health Organization declared COVID-19 a pandemic. As a result, Arizona's governor and many local governments have issued various requirements and recommendations in response to the COVID-19 pandemic, and we expect further actions to continue to be taken. We are closely 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 TEP’s service territory as well as capital markets. These disruptions could continue for a prolonged period of time or become severe. We activated our business continuity plans and continue to reevaluate and reassess protocols and plans as the pandemic conditions evolve. These actions are 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 premises; (ii) imposed travel limitations on employees; (iii) directed employees to work remotely, including elimination of in-person meetings and separation of field crews; (iv) implemented pre-work screening procedures

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conducted prior to entering our facilities; (v) distributed face masks to workforce; and (vi) restricted access to critical facilities. Additional safety protocols have been implemented for work required within customers' 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 voluntarily 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 was approved by the ACC in May 2020 and was returned to customers in the form of bill credits over the June 2020 billing cycle. 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 six months of 2020, we have not experienced a material impact to our results of operations as a result of the COVID-19 pandemic.

Performance - The second quarter of 2020 compared with the second quarter of 2019

TEP reported net income of $57 million in the second quarter of 2020 compared with net income of $42 million in the second quarter of 2019. The increase of $15 million, or 36%, was primarily due to:


•	$13 million in higher retail revenue primarily due to an increase in usage related to favorable weather;


•	$4 million in higher AFUDC due to a FERC Order to adjust the AFUDC calculation and an increase in construction projects;


•	$3 million in higher LFCR revenues;


•	$2 million increase in value of investments used to support certain post-employment benefits as a result of favorable market conditions; and


•	$2 million in lower operations and maintenance expenses related to planned generation outages in 2019 not recurring in 2020.

The increase was partially offset by:


•	$5 million in higher depreciation and amortization expense due to an increase in asset base; and


•	$3 million in higher interest expense primarily related to a long-term debt issuance in April 2020.

Performance - The first six months of 2020 compared with the first six months of 2019

TEP reported net income of $65 million in the first six months of 2020 compared with net income of $68 million in the first six months of 2019. The decrease of $3 million, or 4%, was primarily due to:


•	$8 million in higher depreciation and amortization expense due to an increase in asset base;


•	$7 million decrease in value of investments used to support certain post-employment benefits as a result of unfavorable market conditions;


•	$4 million in higher interest expense primarily related to a long-term debt issuance in April 2020; and


•	$2 million in higher income tax expense primarily due to AMT credits recognized in 2019 not recurring in 2020.

The decrease was partially offset by:


•	$10 million in higher retail revenue primarily due to an increase in usage related to favorable weather;


•	$5 million in higher LFCR revenues; and


•	$5 million in higher AFUDC due to FERC Order to adjust the AFUDC calculation and an increase in construction projects.

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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 shift, and weather patterns.

COVID-19 Pandemic Impacts

The extent of the impact of the COVID-19 pandemic on our operational and financial performance depends 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 rapidly evolving and challenging to predict. Areas that we currently anticipate as likely to be materially impacted and that may have an effect on our results of operations, cash flows, and earnings are noted below.

Retail Sales

As a result of various Executive Orders issued by Arizona's governor in response to the COVID-19 pandemic, energy usage by our commercial and industrial customers has decreased 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, energy usage by our residential customers has increased due to stay at home orders and widespread adoption of work from home practices. We expect the increase to last for the duration of the pandemic response and may continue beyond as companies rethink their work from home practices. In the first six months of 2020, we have not experienced a significant impact to total retail sales as a result of the COVID-19 pandemic.

Electricity sold to retail customers by class of customer in the second quarter of the last three years were as follows:



	Three Months Ended June 30,
(sales in GWh)	2020			2019			2018
Electric Sales
Residential	1,068	47	%	856	41	%	1,019	44	%
Commercial	490	21	%	510	24	%	573	24	%
Industrial, non-Mining	457	20	%	470	22	%	498	21	%
Industrial, Mining	279	12	%	265	13	%	248	11	%
Other	4	—	%	4	—	%	4	—	%
Total Retail Sales by Customer Class	2,298	100	%	2,105	100	%	2,342	100	%

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. 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 six months of 2020 as a result of unfavorable market conditions arising from the COVID-19 pandemic. The value of investments used to support certain post-employment benefits may continue to fluctuate 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 and offered flexible payment arrangements to help customers affected by the COVID-19 pandemic. During the second quarter of 2020, we experienced an increase in accounts receivable balances greater than 90 days as a result of COVID-19 related suspension of service disconnections and the Summer Moratorium. In June 2020, we increased our bad debt reserve rate and estimated the total impact of the moratoriums on operating expenses to be approximately $2 million through the end of 2020. The change in the bad debt reserve rate did not have a significant impact on operating expenses in the second quarter of 2020. We are continuing to assess credit loss risk and may experience additional increases in bad debt expense due to the COVID-19 pandemic.

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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. In May 2020, the ACC approved the request and we returned the funds in the form of customer bill credits over the June 2020 billing cycle.

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

2019 ACC Rate Case

In April 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.

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


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


•	a 7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 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 resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of the Sundt RICE Units;


•	a TEAM 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.

We cannot predict the outcome of the proceeding.

2019 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.

Provisions of the 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 is intended to allow for a more timely recovery of transmission-related costs. If this request is approved, transmission revenues would increase by approximately $7 million annually. As part of the order, the FERC 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. We had reserved $9 million as of June 30, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. We cannot predict the outcome of the proceeding.

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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 issued the ACC Refund Order. The 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. 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 informational filing with the ACC to establish a 2020 customer refund of $35 million. The refund will be returned to customers 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 next rate case. TEP has proposed a TEAM to return the remaining deferred 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 and the TCJA.

Arizona Energy Policy

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy and energy efficiency goals, integrated resource planning, and retail competition for generation services. In 2019 and 2020, the ACC staff and two commissioners prepared different drafts of retail electric competition rules. The ACC discussed those draft rules during workshops, but such rules have not been officially proposed and no changes have been made.

In July 2020, ACC staff issued a proposed order that would adopt new energy rules. The new rules, if adopted, would require affected utilities to, among other things, implement plans designed to supply: (i) 50% of their retail electric sales with renewable energy by 2035; and (ii) 100% of their retail electric sales with clean energy by 2050. The proposed rule would also allow utilities to request cost recovery of compliance in rate proceedings. Also in July 2020, two commissioners issued draft energy rules, which if adopted, would, among other things, require: (i) affected utilities to supply 55% of their retail and wholesale electric sales with clean energy by 2025, with increasing five-year requirements reaching 100% by 2050; and (ii) 55% of the generation capacity owned by affected utilities to be clean energy resources by 2025, with increasing five-year requirements reaching 100% by 2050. The ACC is scheduled to consider both sets of rules at a meeting on July 30, 2020, and could initiate a formal rule-making process to adopt new energy rules. 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 their impact on the Company's financial position or results of operations.

Generation Resource Shift

Our long-term strategy is to continue our shift from carbon-intensive sources to a more sustainable energy portfolio including expanding renewable energy resources while reducing reliance on coal-fired generation resources. In June 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.

2020 IRP

Our 2020 IRP proposal includes a goal of reducing our carbon dioxide emissions 80% compared to levels in 2005 by 2035. To achieve this goal, we will continue the retirement of older fossil-fuel resources and replace these assets with a combination of renewable resources, energy storage, and energy efficiency programs. The 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, we are considering options that include the exit of all ownership interests in coal plants over the next 12 years. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions. The execution of our IRP proposal is dependent on obtaining regulatory recovery approval.

As of June 30, 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.

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Navajo Generating Station

TEP and the co-owners of Navajo retired the generation station in November 2019 and began decommissioning activities. We expect the majority of decommissioning activities to be completed by 2024 with monitoring activities continuing through 2054. TEP is currently recovering the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, we requested recovery of final retirement costs over a 10-year period in the 2019 ACC Rate Case. As of June 30, 2020, the net book value of Navajo was $40 million, with estimated other related costs of $4 million.

Sundt Generating Station

In 2018, the Pima County Department of Environmental Quality approved TEP's air permit, which allowed the Company to place in service 10 natural gas RICE units at Sundt and required the retirement of Sundt Units 1 and 2 in November 2019. We are 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, we requested recovery of final retirement costs over a 10-year period in the 2019 ACC Rate Case. As of June 30, 2020, the net book value of Sundt Units 1 and 2 was $24 million, with estimated other related costs of $1 million.

The Company placed in service five of the RICE units in December 2019, and the remaining five were placed in service in March 2020. The Sundt RICE Units balance the variability of intermittent renewable energy resources. The units replaced 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which were less efficient and lacked the quick start, fast ramp capabilities of the Sundt RICE Units. We requested recovery of the 10 Sundt RICE Units over the useful lives of the assets in the 2019 ACC Rate Case. The total cost of the Sundt RICE Units project was $183 million.

Gila River Generating Station

In 2017, we 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 included a three-year option to purchase the unit. The Company completed the purchase of Gila River Unit 2 in December 2019 for $165 million. The 550 MW of capacity, power, and ancillary services replaced coal-fired generation lost due to early retirements. We 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. The Department of Energy issued a request for information seeking to understand current industry practices surrounding supply chain components of the bulk-power system with comments due August 7, 2020. We are currently developing a response to this request.

Production Tax Credits

Federal renewable electricity Production Tax Credits (PTC) are earned as energy from qualifying wind-powered facilities is generated 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 generated for 2019. The Company will begin earning PTCs once Oso Grande begins generating power to serve our customers. The PTCs are expected to offset costs of the Oso Grande project.

Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. The Company's summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during such period. By contrast, lower sales of power occur during the first quarter of the year, due to mild winter weather in our retail service territory. Seasonal fluctuations affect the comparability of our results of operations.

Interest Rates

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

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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 second quarter and first six months of 2020 compared with the same periods in 2019 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:



	Three Months Ended June 30,				Increase (Decrease)		Six Months Ended June 30,				Increase (Decrease)
(in millions)	2020		2019		Percent		2020		2019		Percent
Operating Revenues
Retail	$	265	$	236	12.3	%	$	457	$	438	4.3	%
Wholesale, Long-Term	7		7		—	%	14		16		(12.5	)%
Wholesale, Short-Term ⁽¹⁾	25		35		(28.6	)%	54		107		(49.5	)%
Transmission	6		8		(25.0	)%	13		16		(18.8	)%
Springerville Units 3 and 4 Participant Billings	18		26		(30.8	)%	38		46		(17.4	)%
Other	19		14		35.7	%	42		36		16.7	%
Total Operating Revenues	$	340	$	326	4.3	%	$	618	$	659	(6.2	)%


⁽¹⁾	Revenues associated with derivatives are primarily returned 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 $340 million in the second quarter of 2020 compared with $326 million in the same period for 2019. The increase of $14 million, or 4%, was primarily due to:


•	$15 million in higher retail revenue primarily due to favorable weather;


•	$13 million in higher retail revenue primarily due to higher fuel and purchase power recoveries due to changes in the PPFAC rate and increased volumes; and


•	$4 million in higher other revenue due to an increase in LFCR revenue.

The increase was partially offset by:


•	$10 million in lower wholesale short-term sales primarily due to a decrease in volumes driven by the expiration of a capacity sale contract in December 2019; and


•	$7 million in lower participant billings related to Springerville Units 3 and 4.

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TEP reported Operating Revenues of $618 million in the first six months of 2020 compared with $659 million in the same period for 2019. The decrease of $41 million, or 6%, was primarily due to:


•	$53 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


•	$7 million in lower participant billings related to Springerville Units 3 and 4.

The decrease was partially offset by:


•	$11 million in higher retail revenue primarily due to favorable weather;


•	$6 million in higher other revenue due to an increase in LFCR revenue; and


•	$3 million in higher retail revenue primarily due to higher fuel and purchase power recoveries due to increased volumes.

The following table provides key statistics impacting Operating Revenues:



	Three Months Ended June 30,		Increase (Decrease)		Six Months Ended June 30,		Increase (Decrease)
(kWh in millions)	2020	2019	Percent		2020	2019	Percent
Electric Sales (kWh) ⁽¹⁾
Retail Sales	2,298	2,105	9.2	%	4,098	3,941	4.0	%
Wholesale, Long-Term	76	74	2.7	%	148	209	(29.2	)%
Wholesale, Short-Term	1,102	1,606	(31.4	)%	2,348	3,653	(35.7	)%
Total Electric Sales	3,476	3,785	(8.2	)%	6,594	7,803	(15.5	)%

Average Revenue Per kWh (Cents/kWh) ⁽²⁾
Retail	11.53	11.21	2.9	%	11.15	11.12	0.3	%
Wholesale, Long-Term	8.51	9.10	(6.5	)%	9.25	7.56	22.4	%
Wholesale, Short-Term	1.87	2.07	(9.7	)%	2.10	2.91	(27.8	)%

Total Retail Customers ⁽³⁾					432,129	427,215	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.

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Operating Expenses

Fuel and Purchased Power Expense

TEP reported Fuel and Purchased Power expense of $110 million in the second quarter of 2020 compared with $104 million in the same period for 2019. The increase of $6 million, or 6%, was primarily due to:


•	$17 million in higher PPFAC recoveries primarily due to changes in the PPFAC rate;


•	$8 million in higher fuel costs primarily due to an increase in natural gas prices; and


•	$4 million in higher purchased power primarily due to an increase in volume.

The increase was partially offset by $21 million in lower fuel costs primarily due to a decrease in Coal-Fired Generation volumes and a decrease in realized losses on gas swaps.

TEP reported Fuel and Purchased Power expense of $201 million in the first six months of 2020 compared with $244 million in the same period for 2019. The decrease of $43 million, or 18%, was primarily due to:


•	$39 million in lower fuel costs primarily due to a decrease in Coal and Gas-Fired Generation volumes and a decrease in natural gas prices; and


•	$13 million in lower purchased power primarily due to a decrease in volume and the purchase of Gila River Unit 2.

The decrease was partially offset by $10 million in higher PPFAC recoveries due to: (i) a decrease in PPFAC eligible costs; and (ii) an increase in the PPFAC rate.

The following provides key statistics impacting Fuel and Purchased Power:



	Three Months Ended June 30,		Increase (Decrease)		Six Months Ended June 30,		Increase (Decrease)
(kWh in millions)	2020	2019	Percent		2020	2019	Percent
Sources of Energy
Coal-Fired Generation	1,126	1,606	(29.9	)%	2,535	3,372	(24.8	)%
Gas-Fired Generation	1,843	1,850	(0.4	)%	3,319	3,681	(9.8	)%
Utility-Owned Renewable Generation	25	19	31.6	%	45	39	15.4	%
Total Generation	2,994	3,475	(13.8	)%	5,899	7,092	(16.8	)%
Purchased Power, Non-Renewable	409	254	61.0	%	579	674	(14.1	)%
Purchased Power, Renewable	217	205	5.9	%	368	350	5.1	%
Total Generation and Purchased Power ⁽¹⁾	3,620	3,934	(8.0	)%	6,846	8,116	(15.6	)%



(cents per kWh)
Average Fuel Cost of Generated Power ⁽²⁾
Coal	2.53	2.42	4.5	%	2.53	2.28	11.0	%
Natural Gas ⁽³⁾	1.82	1.89	(3.7	)%	1.81	2.32	(22.0	)%
Average Cost of Purchased Power ⁽⁴⁾
Purchased Power, Non-Renewable	3.11	2.88	8.0	%	2.96	3.63	(18.5	)%
Purchased Power, Renewable	9.49	9.49	—	%	9.42	9.39	0.3	%


⁽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.

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⁽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 $84 million in the second quarter of 2020 compared with $92 million in the same period for 2019. The decrease of $8 million, or 9%, was primarily due to:


•	$5 million in lower reimbursable maintenance expense related to Springerville Unit 3 due to planned outages in 2019 not recurring in 2020; and


•	$4 million in lower expenses related to remote plants primarily due to the retirement of Navajo in November 2019 and planned outages in 2019 not recurring in 2020.

TEP reported Operations and Maintenance expense of $171 million in the first six months of 2020 compared with $179 million in the same period for 2019. The decrease of $8 million, or 4%, was primarily due to lower reimbursable maintenance expense related to Springerville Unit 3 due to planned outages in 2019 not recurring in 2020.

Depreciation and Amortization Expense

Depreciation and Amortization expense increased by $5 million, or 11%, and $10 million, or 10%, in the second quarter and first six months of 2020, respectively, when compared with the same periods in 2019. The increases were primarily due to higher asset base.

Other Income (Expense)

TEP reported other expense of $9 million in the second quarter of 2020 compared with $17 million in the same period for 2019. The decrease of $8 million, or 47%, was primarily due to:


•	$5 million in higher AFUDC due to a FERC Order to adjust the AFUDC calculation and an increase in construction projects;


•	$3 million in lower finance lease interest expense related to PPFAC recoverable demand charges due to the purchase of Gila River Unit 2 in December 2019;


•	$2 million increase in the value of investments used to support certain post-employment benefits as a result of favorable market conditions; and


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

The decrease was partially offset by $4 million in higher interest expense primarily related to a long-term debt issuance in April 2020.

TEP reported other expense of $29 million in the first six months of 2020 compared with $31 million in the same period for 2019. The decrease of $2 million, or 6%, was primarily due to:


•	$6 million in higher AFUDC due to a FERC Order to adjust the AFUDC calculation and an increase in construction projects;


•	$6 million in lower finance lease interest expense related to PPFAC recoverable demand charges due to the purchase of Gila River Unit 2 in December 2019; and


•	$3 million increase in other income due to an increase in expected return on pension plan assets.

The decrease was partially offset by:


•	$7 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions; and


•	$5 million in higher interest expense primarily related to a long-term debt issuance in April 2020.

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Income Tax Expense

TEP reported Income Tax Expense of $11 million in the second quarter of 2020 compared with $8 million in the same period for 2019. The increase of $3 million, or 38%, was primarily due to $4 million in higher tax expense due to an increase in taxable earnings.

TEP reported Income Tax Expense of $14 million in the first six months of 2020 compared with $11 million in the same period for 2019. The increase of $3 million, or 27%, was primarily due to lower tax credits related to AMT credits recognized in the first quarter of 2019 not recurring in 2020.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

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 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 fund our business activities. Based on our expectations, including possible impacts of COVID-19 on sales, accounts receivable collections, and capital spending, we 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 bank and capital markets.

Available Liquidity



(in millions)	June 30, 2020
Cash and Cash Equivalents	$	61
Amount Available under Revolving Credit Agreement ⁽¹⁾	238
Total Liquidity	$	299


⁽¹⁾	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 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)
(in millions)	2020			2019			Percent
Operating Activities	$	188		$	163		15.3	%
Investing Activities	(506		)	(221		)	129.0	%
Financing Activities	368			(11		)	*
Net Increase (Decrease)	50			(69		)	(172.5	)%
Beginning of Period	28			153			(81.7	)%
End of Period ⁽¹⁾	$	78		$	84		(7.1	)%

* Not meaningful


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

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Operating Activities

In the first six months of 2020, net cash flows from operating activities increased by $26 million compared with the same period in 2019. The increase was primarily due to higher: (i) customer usage related to favorable weather; and (ii) fuel and purchase power recoveries as a result of changes in the PPFAC rate. The increase was partially offset by changes in working capital related to the timing of billing collections and payments.

Investing Activities

In the first six months of 2020, net cash flows used for investing activities increased by $285 million compared with the same period in 2019 primarily due to: (i) higher capital expenditures primarily due to $236 million in payments for the Oso Grande project under the build-transfer agreement; and (ii) a $9 million payment in other investments.

Financing Activities

In the first six months of 2020, net cash flows from financing activities increased by $379 million compared with the same period in 2019 primarily due to: (i) higher proceeds related to the issuance of senior unsecured notes in April 2020, net of repayments of borrowings under the credit facilities; and (ii) an increase in equity contributions from UNS Energy.

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, 2020, TEP had no short-term investments.

Access to Credit Agreements

We have access to working capital through our credit 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 June 30, 2020, there was no amount available under the 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 LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of June 30, 2020, there was $238 million available under the 2015 Credit Agreement.

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

Debt Financing

We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings.

In February 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 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.

We anticipate issuing long-term debt in the third quarter of 2020.

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Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of June 30, 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 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.

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, 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 $50 million and $200 million from UNS Energy in the second quarter and first six months of 2020, respectively, and received no equity contributions in the second quarter or first six months of 2019.

Dividends Paid to Parent

TEP did not declare or pay dividends to UNS Energy in the second quarter or first six months of 2020 or 2019. On July 23, 2020, TEP declared a $38 million dividend to UNS Energy, which was paid July 27, 2020.

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 in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of June 30, 2020, TEP had posted no cash or LOCs as credit enhancements with its counterparties related to our wholesale marketing or risk management activities.

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 have reduced forecasted capital expenditures for 2020 due to prioritizing certain projects and postponing others. In the first six months of 2020, there have been no material changes to capital expenditures as reported in our 2019 Annual Report on Form 10-K.

Oso Grande Wind Project

In 2019, we entered into a Build-Transfer Agreement (BTA) to develop Oso Grande by December 2020. The Oso Grande project will add approximately 250 MW of wind-powered electric generation, increasing our total renewable nominal generation capacity to over 500 MW, which includes PPAs and owned utility-scale generation. The project is estimated to cost $422 million, which includes, among other costs, $16 million for AFUDC and $397 million related to the BTA. As of June 30, 2020, total costs of construction incurred from inception was $300 million, which includes, among other costs, $9 million for AFUDC and $283 million related to the BTA. The project costs are currently included in Construction Work in Progress on the Condensed Consolidated Balance Sheets.

Contractual Obligations

In the first six months of 2020, there were no material changes outside the ordinary course of business to contractual obligations as reported in our 2019 Annual Report on Form 10-K.

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Off-Balance Sheet Arrangements

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

TEP did not make any U.S. federal or Arizona State income tax payments in the first six months of 2020 due to existing net operating loss and tax credit carryforwards in those jurisdictions. Based on our remaining tax carryforward balances, we do not anticipate making federal or state income tax payments of a material nature for the next several years.

Under the TCJA, existing AMT credit carryforwards could be refunded or used to offset U.S. federal income tax 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 expects to receive approximately $14 million in AMT credit refunds by the end of 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 recorded deferred deposits of $2 million as of June 30, 2020, in Accrued Taxes Other than Income Taxes on the Condensed Consolidated Balance Sheets. We expect the total deferred deposits to be approximately $6 million, and be paid to the IRS in equal payments in 2021 and 2022.

Environmental Matters

The Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon dioxide (CO₂), particulate matter, mercury and other by-products produced by generation facilities. 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 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 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 2 had been selected for potential emissions controls evaluation.

TEP conducted the potential emissions controls evaluation, commonly referred to as the four factor analysis, for both facilities. These evaluations were submitted to the ADEQ 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 must submit the revised SIP to the EPA for approval by July 2021. Based on current Regional Haze requirement time-frames, TEP anticipates that compliance strategies, if any, will likely be required to be implemented three to five years after the 2021 SIP submittal date.

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Greenhouse Gas Regulation

In August 2015, the EPA issued the Clean Power Plan (CPP) limiting CO₂ emissions from existing and new fossil fuel-based generation facilities. The CPP establishes state-level CO₂ emission rates and mass-based goals that apply to fossil fuel-based generation. The plan 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 generation facilities is defined as 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.

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 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.

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 will continue to work with other Arizona utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed.

Legal challenges 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 (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. Our share of costs to comply with the CCR rule at Four Corners is estimated to be $3 million. This includes estimated costs for corrective action for two CCR units at the facility, which will be incurred over 30 years. Arizona Public Service began an assessment of corrective measures in 2019, and expects the assessment to continue through late 2020.

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. On February 20, 2020, the EPA proposed a federal CCR permitting program. The comment period for this rulemaking closed on July 20, 2020. TEP does not anticipate a material impact on operations or financial results from the proposed rule revisions.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to apply accounting policies and make estimates, judgments, and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that there have been no significant changes during the six months ended June 30, 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 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.

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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 2019 Annual Report on Form 10-K, other than as described below.

Credit Risk

In response to the COVID-19 pandemic, we have increased our monitoring of the effects of the economic slowdown on counterparties’ abilities to perform under their contractual obligations.

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, 2020. There was no change in TEP’s internal control over financial reporting during the quarter ended June 30, 2020, that materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

For a description of certain legal proceedings affecting TEP, refer to Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 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 2019 Annual Report on Form 10-K, except the additional risk factor noted below, which is an update to the risk factor included in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020:

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 economy on a global, national, and local level, disrupted global supply chains, and created significant volatility and disruption of financial markets. The responses from governmental authorities and companies to reduce the spread of the COVID-19 pandemic have significantly reduced economic activity through various containment measures including, among others, business closures, work stoppages or work-from-home orders, shuttering of public spaces and events, and/or severe restrictions of global and regional travel.

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 factors beyond our control, including the duration, spread, and severity of the pandemic, and how quickly and to what extent normal economic and operating conditions resume, 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.

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, 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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		TUCSON ELECTRIC POWER COMPANY
		(Registrant)

Date:	July 29, 2020	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)