tep-20210630

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, 2021

☐ 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 28, 2021.

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 Cash Flows			2
Condensed Consolidated Balance Sheets			3
Condensed Consolidated Statements of Changes in Stockholder's Equity			5
Notes to Condensed Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Critical Accounting Policies and Estimates			35
New Accounting Standards Issued and Not Yet Adopted			35
Item 3. Quantitative and Qualitative Disclosures about Market Risk			36
Item 4. Controls and Procedures			36

PART II

Item 1. Legal Proceedings			37
Item 1A. Risk Factors			37

Item 6. Exhibits			38
Signatures			39

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 letter of credit sublimit of $50 million; the credit agreement matures in October 2022
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 Annual Report on Form 10-K						TEP's Annual Report on Form 10-K for the year ended December 31, 2020
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
2020 Rate Order						A rate order issued by the ACC resulting in a new rate structure for TEP, effective on January 1, 2021

ACC						Arizona Corporation Commission
ACC Refund Order						An order issued in 2018 by the ACC approving TEP’s proposal to return savings from TEP’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


BTA						Build-Transfer Agreement

COVID-19						Coronavirus Disease 2019
DG						Distributed Generation
DSM						Demand Side Management
EDIT						Excess Deferred Income Taxes
EE Standards						Energy Efficiency Standards


FERC						Federal Energy Regulatory Commission
GAAP						Generally Accepted Accounting Principles in the United States of America
IRS						Internal Revenue Service
LFCR						Lost Fixed Cost Recovery

LOC						Letter(s) of Credit
OATT						Open Access Transmission Tariff

PPA						Power Purchase Agreement
PPFAC						Purchased Power and Fuel Adjustment Clause
PTC						Production Tax Credit
RES						Renewable Energy Standard
Retail Rates						Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment



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 of each year
TCJA						Tax Cuts and Jobs Act
TEAM						Tax Expense Adjustor Mechanism

ENTITIES AND GENERATING STATIONS


APS						Arizona Public Service Company

iii


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

Navajo						Navajo Generating Station
Oso Grande						A 250 MW nominal capacity wind-powered electric generation facility, located 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						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 such 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 2020 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Form 10-Q; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q; 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 or state legislature'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 final outcome of the 2019 FERC Rate Case; unfavorable rulings, penalties, or findings by the FERC; 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 our 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, including renewable generation resources; participation in the Energy Imbalance Market; the extent of the impact of the COVID-19 pandemic on our business and operations, and the economic and societal disruptions resulting from the COVID-19 pandemic and government actions taken in response 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,
	2021		2020		2021		2020
Operating Revenues	$	392,661	$	339,705	$	728,204	$	618,261

Operating Expenses
Fuel	80,497		62,697		171,655		125,996
Purchased Power	50,442		28,833		81,819		47,151
Transmission and Other PPFAC Recoverable Costs	15,660		12,005		29,561		22,600
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(7,968)		6,378		(24,960)		5,196
Total Fuel and Purchased Power	138,631		109,913		258,075		200,943
Operations and Maintenance	94,906		84,032		206,094		171,487
Depreciation	49,698		47,123		97,456		93,622
Amortization	10,540		7,042		21,171		13,998
Taxes Other Than Income Taxes	15,237		14,643		30,794		29,552
Total Operating Expenses	309,012		262,753		613,590		509,602

Operating Income	83,649		76,952		114,614		108,659

Other Income (Expense)
Interest Expense	(23,134)		(22,572)		(44,196)		(43,053)
Allowance For Borrowed Funds	1,899		2,013		4,601		4,895
Allowance For Equity Funds	5,008		7,189		12,102		10,223
Unrealized Gains (Losses) on Investments	1,691		3,276		3,555		(3,151)
Other, Net	2,762		1,339		5,570		2,192
Total Other Income (Expense)	(11,774)		(8,755)		(18,368)		(28,894)

Income Before Income Tax Expense	71,875		68,197		96,246		79,765
Income Tax Expense	8,125		10,707		9,952		14,357
Net Income	$	63,750	$	57,490	$	86,294	$	65,408

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,
	2021		2020
Cash Flows from Operating Activities
Net Income	$	86,294	$	65,408
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	97,456		93,622
Amortization Expense	21,171		13,998

Amortization of Debt Issuance Costs	1,405		1,280
Use of Renewable Energy Credits for Compliance	24,209		21,664
Deferred Income Taxes	9,713		19,866

Pension and Other Postretirement Benefits Expense	7,671		7,442
Pension and Other Postretirement Benefits Funding	(6,190)		(4,955)

Allowance for Equity Funds Used During Construction	(12,102)		(10,223)
Regulatory Deferral, ACC Refund Order	—		8,817



Changes in Current Assets and Current Liabilities:
Accounts Receivable	(46,307)		(11,386)
Materials, Supplies, and Fuel Inventory	(14,439)		3,847
Regulatory Assets	(29,294)		(1,500)

Other Current Assets	(17,093)		2,121
Accounts Payable and Accrued Charges	41,625		(20,317)

Income Taxes Payable, Net	(353)		(7,154)
Regulatory Liabilities	(10,352)		3,213
Other, Net	14,942		2,661
Net Cash Flows—Operating Activities	168,356		188,404
Cash Flows from Investing Activities
Capital Expenditures	(239,970)		(473,881)



Purchase Intangibles, Renewable Energy Credits	(27,810)		(25,746)

Purchase, Other Investments	—		(8,556)
Contributions in Aid of Construction	3,262		2,329

Net Cash Flows—Investing Activities	(264,518)		(505,854)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	35,000		105,000
Repayments of Borrowings, Revolving Credit Facility	(35,000)		(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	322,231		346,983


Payments of Finance Lease Obligations	—		(11,535)

Contribution from Parent	50,000		200,000
Other, Net	(2,328)		(2,632)
Net Cash Flows—Financing Activities	369,903		367,816
Net Increase in Cash, Cash Equivalents, and Restricted Cash	273,741		50,366
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	82,003		28,472
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	355,744	$	78,838

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, 2021		December 31, 2020
ASSETS
Utility Plant
Plant in Service	$	7,652,210	$	7,073,292

Construction Work in Progress	279,346		627,382
Total Utility Plant	7,931,556		7,700,674
Accumulated Depreciation and Amortization	(2,755,043)		(2,645,333)

Total Utility Plant, Net	5,176,513		5,055,341

Investments and Other Property	79,186		76,299

Current Assets
Cash and Cash Equivalents	336,131		60,960
Accounts Receivable (Net of Allowance for Credit Losses of $12,411 and $13,260)	219,407		173,412
Fuel Inventory	28,356		21,946
Materials and Supplies	135,551		126,788
Regulatory Assets	176,208		123,588
Derivative Instruments	31,198		16,094

Other	45,396		23,895
Total Current Assets	972,247		546,683
Regulatory and Other Assets
Regulatory Assets	269,402		318,474
Derivative Instruments	2,866		725
Other	85,670		92,605
Total Regulatory and Other Assets	357,938		411,804
Total Assets	$	6,585,884	$	6,090,127

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, 2021		December 31, 2020
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, 2021 and December 31, 2020)	$	1,696,539	$	1,646,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	798,491		712,197
Accumulated Other Comprehensive Loss	(10,504)		(10,942)
Total Common Stock Equity	2,478,169		2,341,437
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2021 and December 31, 2020)	—		—

Long-Term Debt, Net	2,133,935		1,814,059
Total Capitalization	4,612,104		4,155,496
Current Liabilities
Current Maturities of Long-Term Debt, Net	249,901		249,752


Accounts Payable	161,404		109,461
Accrued Taxes Other than Income Taxes	54,291		50,278
Accrued Employee Expenses	32,785		35,129
Accrued Interest	17,606		16,337
Regulatory Liabilities	154,348		151,189
Customer Deposits	12,101		16,450
Derivative Instruments	54,228		27,789
Other	24,051		22,031
Total Current Liabilities	760,715		678,416
Regulatory and Other Liabilities
Deferred Income Taxes, Net	508,793		492,919
Regulatory Liabilities	341,048		390,164
Pension and Other Postretirement Benefits	160,545		163,652
Derivative Instruments	17,238		37,958
Other	185,441		171,522
Total Regulatory and Other Liabilities	1,213,065		1,256,215

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	6,585,884	$	6,090,127

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, 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


Balances as of March 31, 2021	$	1,646,539	$	(6,357)	$	734,741	$	(10,723)	$	2,364,200
Net Income					63,750				63,750
Other Comprehensive Income, Net of Tax							219		219

Contribution from Parent	50,000								50,000

Balances as of June 30, 2021	$	1,696,539	$	(6,357)	$	798,491	$	(10,504)	$	2,478,169


	Six Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
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


Balances as of December 31, 2020	$	1,646,539	$	(6,357)	$	712,197	$	(10,942)	$	2,341,437
Net Income					86,294				86,294
Other Comprehensive Income, Net of Tax							438		438

Contribution from Parent	50,000								50,000

Balances as of June 30, 2021	$	1,696,539	$	(6,357)	$	798,491	$	(10,504)	$	2,478,169

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 437,000 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 TEP 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 2020 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a 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, 2021, 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)	2021		2020
Cash and Cash Equivalents	$	336	$	61
Restricted Cash included in:
Investments and Other Property	18		16
Current Assets—Other	2		2
Total Cash, Cash Equivalents, and Restricted Cash	$	356	$	79

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.

Uncertain Tax Position

In February 2021, TEP received approval from the IRS for a change in accounting method on uncertain tax positions, resulting in a $17 million decrease in uncertain tax position obligations on a prospective basis.

Income Tax Expense

TEP began realizing PTC benefits during 2021 as Oso Grande was placed in service in May 2021. TEP includes projected PTC benefits in the Company's estimated annual effective tax rate calculation. TEP realized PTC benefits of $4 million and $6 million in Income Tax Expense in the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2021.

Depreciation

Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. As part of the 2020 Rate Order, the ACC approved new annual depreciation rates based on a 2018 depreciation study for the major classes of Plant in Service, except transmission, effective January 1, 2021. In March 2021, TEP transferred $33 million from Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of the revised depreciation rates on estimated cost of removal.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the Financial Accounting Standards Board 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

RATE CASE MATTERS

2020 Rate Order

In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.

Provisions of the 2020 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $58 million over test year retail revenues;

•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%; and

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

In addition, the 2020 Rate Order established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In January 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. TEP cannot predict the timing or outcome of these proceedings.

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.

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. In February 2021, a Presiding Judge was appointed to continue the formula rate case proceeding after the settlement procedures resulted in an impasse. All rates charged under the revised OATT pursuant to the FERC order are subject to refund until the proceeding concludes. TEP had reserved $21 million as of June 30, 2021, and $15 million as of December 31, 2020, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP cannot predict the outcome of the proceeding.

OTHER FERC MATTERS

In January 2021, the FERC notified TEP that it is commencing an audit that is intended to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit will cover the period of January 1, 2018 to the present. TEP cannot predict the outcome or findings, if any, of the FERC audit at this time.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for more timely recovery of certain costs through recovery mechanisms. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2021		2020		2021		2020
Beginning of Period	$	40	$	36	$	23	$	36
Deferred Fuel and Purchased Power Costs (1)	83		67		150		115
PPFAC and Base Power Recoveries (2)	(76)		(75)		(126)		(123)
End of Period	$	47	$	28	$	47	$	28

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

(2)In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021.

Tax Expense Adjustor Mechanism

The TEAM allows for the timely recovery of future significant income tax changes. The TEAM provides the Company the ability to pass through as a kWh surcharge: (i) the TCJA Regulatory Deferral balance to the initial 2021 TEAM rate; (ii) the change in EDIT compared to the test year; and (iii) the income tax effects of tax legislation that materially impacts TEP's 2018 test year revenue requirements. The TEAM went into effect January 1, 2021, as approved in the 2020 Rate Order. TEP's regulatory liability balance related to the TEAM is $11 million as of June 30, 2021 and $29 million as of December 31, 2020 in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP refunded $18 million to customers in the six months ended June 30, 2021.

Federal Tax Legislation

In 2018, the ACC approved TEP’s proposal to return savings from TEP’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 reflected the return of a portion of the savings. TEP recognized a reduction in Operating Revenues on the Condensed Consolidated Statements of Income of $9 million and $16 million in the three and six months ended June 30, 2020, respectively, related to the ACC approved refunds. As part of the 2020 Rate Order, the balances in the regulatory liability deferral and TCJA balancing account were moved to the TEAM regulatory account in December 2020.

Renewable Energy Standard

The ACC’s RES requires Arizona-regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2021 is 11% of retail electric sales, which will increase annually until renewable retail sales represent at least 15% by 2025. The RES also requires that DG account for 30% of the renewable energy requirement. Arizona utilities are required to file annual RES implementation plans for review and approval by the ACC.

The most recent annual implementation plan approved by the ACC was TEP's 2019 RES implementation plan with a budget amount of $55 million. The approved amounts fund: (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 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 both 2021 and 2020 related to the performance incentive 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 $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 2021, TEP filed its 2022 energy efficiency implementation plan with a budget of $23 million.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. 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)	2021		2020		2021		2020
LFCR Revenues	$	3	$	10	$	9	$	22

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, 2021		December 31, 2020
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	162	$	166
Derivatives (Note 9)	9	56		55
Lost Fixed Cost Recovery	2	50		59
Under Recovered Purchased Energy Costs	1	47		23
Early Generation Retirement Costs	Various	40		43
Property Tax Deferrals (1)	1	26		26
Income Taxes Recoverable through Future Rates (2)	Various	23		27
Final Mine Reclamation and Retiree Healthcare Costs (3)	8	21		20
Springerville Unit 1 Leasehold Improvements (4)	2	5		7
Other Regulatory Assets	Various	15		16
Total Regulatory Assets		445		442
Less Current Portion	1	176		124
Total Non-Current Regulatory Assets		$	269	$	318


Regulatory Liabilities
Income Taxes Payable through Future Rates (2)	Various	$	286	$	298
Net Cost of Removal (5)	Various	86		125
Renewable Energy Standard	Various	61		63
Transmission Revenue Subject to Refund—FERC	Various	21		15
Tax Reform Bill Credit	Various	11		29


Other Regulatory Liabilities	Various	30		11
Total Regulatory Liabilities		495		541
Less Current Portion	1	154		151
Total Non-Current Regulatory Liabilities		$	341	$	390

(1)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.

(2)Amortized over five years, 10 years, or the lives of the assets.

(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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(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, 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, and general and intangible plant which are not yet expended. As a result of the 2020 Rate Order, TEP transferred costs from Net Cost of Removal to Accumulated Depreciation and Amortization. See Note 1 for additional information related to new depreciation rates approved as part of the 2020 Rate Order.

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, 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. TEP pays a return on the majority of its regulatory liability balances.

PLANT IN SERVICE

In 2019, TEP entered into a BTA to develop Oso Grande. In May 2021, Oso Grande was placed in service, adding 250 MW of wind-powered electric generation, increasing TEP's total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 600 MW. As of June 30, 2021, there was $437 million in costs related to Oso Grande in Plant in Service on the Condensed Consolidated Balance Sheets, of which $388 million and $33 million related to the BTA and AFUDC, respectively.

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)	2021		2020		2021		2020
Retail (1)	$	297	$	265	$	512	$	457
Wholesale (2)	47		30		103		66
Other Services	25		23		61		47
Revenues from Contracts with Customers	369		318		676		570
Alternative Revenues	3		10		10		24
Other	21		12		42		24
Total Operating Revenues	$	393	$	340	$	728	$	618

(1)In 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. See Note 2 for more information regarding the 2020 Rate Order.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 4. ACCOUNTS RECEIVABLE

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


(in millions)	June 30, 2021		December 31, 2020
Retail	$	94	$	90
Retail, Unbilled	70		41
Retail, Allowance for Credit Losses	(12)		(13)
Wholesale (1)	38		33
Due from Affiliates (Note 5)	14		9
Other	15		13
Accounts Receivable	$	219	$	173

(1)Includes $19 million as of June 30, 2021, and $7 million as of December 31, 2020, of receivables related to revenue from derivative instruments.

ALLOWANCE FOR CREDIT LOSSES

TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. 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 June 30,				Six Months Ended June 30,
(in millions)	2021		2020		2021		2020
Beginning of Period	$	(13)	$	(6)	$	(13)	$	(6)
Credit Loss Expense	—		(1)		(1)		(2)
Write-offs	1		—		2		1

End of Period	$	(12)	$	(7)	$	(12)	$	(7)

Service Disconnection Moratoriums

In 2019, the ACC enacted the Summer Moratorium. The Summer Moratorium has remained in effect for 2020 and 2021 to date and will remain in effect each year until the ACC permanently adopts new rules regarding electric service disconnections. In addition, as a result of the COVID-19 pandemic, TEP voluntarily suspended service disconnections and late fees from March 2020 through January 2021 for all customers who would have otherwise been disconnected.

In December 2020, the ACC enacted a bill credit and payment program for residential customers who are behind on their electric bills as a result of the COVID-19 pandemic. For qualifying customers, the program included: (i) an upfront bill credit applied to their December 2020 bill; and (ii) automatic enrollment into an eight-month payment plan. TEP also voluntarily created payment arrangements for commercial customers similarly affected by COVID-19 during this period. During the second quarter of 2021, TEP experienced accounts receivable collection activity consistent with pre-COVID-19 pandemic conditions and has made significant progress collecting aged accounts receivable from customers impacted by the COVID-19 pandemic.

TEP will continue to monitor collection activity and adjust its allowance for credit losses as needed.

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. Effective January 1, 2021, TEP hired SES's employees and will no longer utilize SES's services.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2021		December 31, 2020
Receivables from Related Parties
UNS Electric	$	13	$	6
UNS Gas	1		1
UNS Energy	—		2








Total Due from Related Parties	$	14	$	9

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




Total Due to Related Parties	$	4	$	5

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2021		2020		2021		2020
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	3	$	2	$	6	$	4
Wholesale Revenues, UNS Electric (2)	4		—		5		—
Control Area Services, UNS Electric (3)	1		1		3		2
Common Costs, UNS Energy Affiliates (4)	5		4		10		9


Goods and Services Provided by Affiliates to TEP
Wholesale Revenues, UNS Electric (1)	$	1	$	—	$	1	$	—
Supplemental Workforce, SES (5)	—		3		—		7
Corporate Services, UNS Energy (6)	2		2		4		3
Corporate Services, UNS Energy Affiliates (7)	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 capacity, power, and ancillary services under a tolling PPA. See Note 7 for additional information related to the tolling PPA.

(3)TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.

(4)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.

(5)SES provided supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges were based on cost of services performed and deemed reasonable by management.

(6)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 85% of UNS Energy's allocated costs. The Corporate Services, UNS Energy line 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, 2021 and 2020, respectively.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DIVIDENDS PAID TO PARENT

On July 26, 2021, TEP declared and paid a $38 million dividend to UNS Energy.

NOTE 6. DEBT AND CREDIT AGREEMENTS

There have been no significant changes to TEP's debt or credit agreements from those reported in its 2020 Annual Report on Form 10-K, except as noted below.

DEBT

Issuance

In May 2021, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2051. TEP may redeem the debt prior to November 1, 2050, with a make-whole premium plus accrued interest. On or after November 1, 2050, TEP may redeem the debt at par plus accrued interest. TEP intends to use the net proceeds to redeem debt in August 2021 and for general corporate purposes. On July 20, 2021, TEP issued a revocable notice to redeem $250 million aggregate principal amount of 5.15% senior unsecured notes at par on August 20, 2021. These notes have a maturity date of November 15, 2021.

CREDIT AGREEMENTS

Amounts borrowed under the credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets.

2015 Credit Agreement

In January 2020, $12 million in LOCs with fees accruing at a rate of 1.00% per annum were issued pursuant to TEP taking ownership of Oso Grande under the BTA. In May 2021, Oso Grande was placed in service and a $2 million LOC was cancelled. The remaining $10 million LOC remains outstanding. As of July 28, 2021, there was $240 million available under the 2015 Credit Agreement revolving credit commitment and LOC facility.

2019 Credit Agreement

In December 2019, TEP entered into an unsecured credit agreement with a maturity date of December 2020 that provided for $225 million in term loans (2019 Credit Agreement), of which $165 million was borrowed as of December 2019. In March 2020, TEP borrowed the remaining available balance of $60 million. Amounts borrowed 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. In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the outstanding term loans and the agreement was terminated.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

In addition to those reported in its 2020 Annual Report on Form 10-K, TEP entered into the following long-term commitments through June 30, 2021:


(in millions)	2021		2022		2023		2024		2025		Thereafter		Total
Minimum Purchase Commitments
Fuel, Including Transportation	$	—	$	14	$	12	$	—	$	—	$	—	$	26
Purchased Power	41		47		47		—		—		—		135
Purchase Commitments
Renewable Power Purchase Agreements	3		8		8		8		8		111		146
Total Commitments	$	44	$	69	$	67	$	8	$	8	$	111	$	307

Costs for Purchased Power and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of renewable PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.

Fuel, Including Transportation

In June 2021, TEP entered into natural gas commodity purchase agreements at market prices that expire through the fourth quarter of 2023. The commitment amounts included in the table above are based on projected market prices as of June 30, 2021.

Purchased Power

In June 2021, TEP entered into tolling PPAs to purchase and receive up to 300 MW of capacity, power, and ancillary services from June 15 through October 15 in 2021, 2022, and 2023. TEP will pay monthly capacity charges and variable power charges.

TEP entered into tolling PPAs with UNS Electric in June and July 2021 to sell and deliver up to 150 MW of the capacity, power, and ancillary services over the same time periods. UNS Electric will pay TEP monthly capacity charges equal to 50% of TEP's monthly capacity charges and variable power charges. TEP's commitment does not reflect any reduction for the subsequent sale of capacity.

Renewable Power Purchase Agreements

TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. In April 2021, one of these facilities and the associated battery storage achieved commercial operation. The PPA expires in April 2041. While TEP is not required to make payments under this agreement if power is not delivered, estimated future payments, excluding battery storage, are included in the table above.

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 to retail customers final mine reclamation costs, as a component of fuel costs. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of final mine reclamation costs at both mines is $47 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 $40 million as of June 30, 2021 and December 31, 2020, 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 generation participation agreements with participants at San Juan, Four Corners, and Luna Generating Station, which expire in 2022, 2041, and 2046, respectively. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generation facility. 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. Relative to Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party. 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 by the non-defaulting parties is $250 million at Four Corners. As of June 30, 2021, there have been no such payment defaults under any of the participation agreements.

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 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2021		2020		2021		2020
Service Cost	$	5	$	4	$	1	$	1
Non-Service Cost (1)
Interest Cost	4		4		1		1
Expected Return on Plan Assets	(9)		(8)		(1)		(1)
Amortization of Net Loss	3		2		—		—
Net Periodic Benefit Cost	$	3	$	2	$	1	$	1


	Pension Benefits				Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2021		2020		2021		2020
Service Cost	$	10	$	8	$	3	$	2
Non-Service Cost (1)
Interest Cost	7		8		1		1
Expected Return on Plan Assets	(17)		(15)		(1)		(1)
Amortization of Net Loss	5		4		—		—
Net Periodic Benefit Cost	$	5	$	5	$	3	$	2

(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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

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


	Level 1		Level 2		Total
(in millions)	June 30, 2021
Assets
Cash Equivalents (1)	$	250	$	—	$	250
Restricted Cash (1)	20		—		20
Energy Derivative Contracts, Regulatory Recovery (2)	—		33		33
Energy Derivative Contracts, No Regulatory Recovery (2)	—		1		1
Total Assets	270		34		304
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(71)		(71)

Total Liabilities	—		(71)		(71)
Total Assets (Liabilities), Net	$	270	$	(37)	$	233


(in millions)	December 31, 2020
Assets

Restricted Cash (1)	$	21	$	—	$	21
Energy Derivative Contracts, Regulatory Recovery (2)	—		14		14
Energy Derivative Contracts, No Regulatory Recovery (2)	—		3		3
Total Assets	21		17		38
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(66)		(66)


Total Liabilities	—		(66)		(66)
Total Assets (Liabilities), Net	$	21	$	(49)	$	(28)

(1)Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.

(2)Energy Derivative Contracts include gas swap agreements and forward power purchase and sale 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
			Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted
(in millions)	June 30, 2021
Derivative Assets
Energy Derivative Contracts	$	34	$	26	$	—	$	8
Derivative Liabilities
Energy Derivative Contracts	(71)		(26)		(24)		(21)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)


(in millions)	December 31, 2020
Derivative Assets
Energy Derivative Contracts	$	17	$	14	$	—	$	3
Derivative Liabilities
Energy Derivative Contracts	(66)		(14)		(7)		(45)

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 TEP'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)	2021		2020		2021		2020
Unrealized Net Gain	$	17	$	6	$	13	$	15

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)	2021		2020		2021		2020
Operating Revenues	$	—	$	4	$	1	$	5

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivative Volumes

As of June 30, 2021, 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, 2021	December 31, 2020
Power Contracts GWh	2,603	4,143
Gas Contracts BBtu	134,891	111,585

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 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 parties' assessments of each other'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 $76 million as of June 30, 2021, compared with $60 million as of December 31, 2020. As of June 30, 2021, TEP had $24 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets—Other on the Condensed Consolidated Balance Sheets. As of July 28, 2021, there was $19 million of cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on June 30, 2021, TEP would have been required to post an additional $52 million of collateral of which $41 million relates to outstanding net payable balances for settled positions.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. 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)		June 30, 2021		December 31, 2020		June 30, 2021		December 31, 2020
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,384	$	2,064	$	2,627	$	2,363

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:


	Six Months Ended June 30,
(in millions)	2021		2020
Accrued Capital Expenditures	$	36	$	29
Asset Retirement Obligations Increase (Decrease) (1)	13		(1)
Renewable Energy Credits	5		5

Net Cost of Removal Decrease (2)	(36)		(5)

(1)The non-cash additions to Asset Retirement Obligations and related capitalized assets primarily represent a new obligation related to Oso Grande.

(2)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. See Note 1 for additional information related to new depreciation rates approved as part of the 2020 Rate Order.

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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 capital expenditures and 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 2020 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 2020, we announced our long-term goal to reduce carbon emissions by exiting coal-fired generation over the next 11 years and increasing renewable energy resources and energy storage. These goals may be impacted by various federal and state energy policies, including 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

The COVID-19 pandemic caused changes in consumer and business behavior and disrupted economic activity in TEP’s service territory. We activated our business continuity plans and we continue to reevaluate and reassess protocols and plans as pandemic conditions evolve. Our protocols and plans are intended to support the continued delivery of safe and reliable service to our customers and the communities we serve.

We cannot predict the ultimate effects of the pandemic on the economy or our service territory. We continue to monitor developments affecting our workforce, customers, suppliers, and operations. We have not experienced a material impact to our results of operations as a result of the COVID-19 pandemic.

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Performance - The second quarter of 2021 compared with the second quarter of 2020

TEP reported net income of $64 million in the second quarter of 2021 compared with net income of $57 million in the second quarter of 2020. The increase of $7 million, or 12%, was primarily due to:

•$26 million in higher retail revenue primarily due to an increase in rates as approved in the 2020 Rate Order and favorable weather;

•$3 million in lower income tax expense primarily due to an increase in PTCs; and

•$2 million in higher transmission revenue primarily due to an increase in sales volume.

The increase was partially offset by:

•$6 million in higher operations and maintenance expenses due to an increase in planned generation outages in 2021;

•$5 million in lower LFCR revenues as a result of a rate adjustment as approved in the 2020 Rate Order;

•$5 million in higher depreciation and amortization expense due to an increase in asset base and an increase in depreciation rates and amortization as a result of the 2020 Rate Order;

•$4 million in lower gains from wholesale transactions;

•$2 million in higher operations and maintenance expenses due to an increase in employee benefits expense;

•$2 million in lower AFUDC due to a 2020 FERC Order that provided for an adjustment in the AFUDC calculation not recurring in 2021; and

•$2 million decrease in the value of investments used to support certain post-employment benefits as a result of less favorable market conditions.

Performance - The first six months of 2021 compared with the first six months of 2020

TEP reported net income of $86 million in the first six months of 2021 compared with net income of $65 million in the first six months of 2020. The increase of $21 million, or 32%, was primarily due to:

•$43 million in higher retail revenue primarily due to an increase in rates as approved in the 2020 Rate Order and favorable weather;

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

•$6 million in lower income tax expense primarily due to an increase in PTCs and a decrease in EDIT amortization;

•$6 million in higher transmission revenue primarily due to an increase in sales volume; and

•$1 million in higher AFUDC as a result of a change in the AFUDC rate; partially offset by a 2020 FERC Order that provided for an adjustment in the AFUDC calculation not recurring in 2021.

The increase was partially offset by:

•$11 million in lower LFCR revenues as a result of a rate adjustment as approved in the 2020 Rate Order;

•$10 million in higher operations and maintenance expenses due to an increase in planned generation outages in 2021;

•$10 million in higher depreciation and amortization expense due to an increase in asset base and an increase in depreciation rates and amortization as a result of the 2020 Rate Order;

•$6 million in higher operations and maintenance expenses due to an increase in employee wages and benefits expense; and

•$4 million in lower gains from wholesale transactions.

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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 economic impacts of the COVID-19 pandemic, regulatory matters, generation resource strategy, 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 by governmental authorities and regulators; (iii) impacts on our customers, employees, and vendors; and (iv) actions by us to assist our customers through this crisis. These developments are continuously evolving and are challenging to predict. Areas currently impacted, and areas we expect to continue to be impacted, that may have an effect on our results of operations, cash flows, and earnings are noted below.

Retail Sales

The COVID-19 pandemic changed consumer and business behavior as a result of safety measures taken to combat the spread. In 2020, energy usage by our commercial and industrial customers decreased below average levels experienced in prior periods, and energy usage by our residential customers increased due to stay at home orders and widespread adoption of work from home practices. However, in the first half of 2021, usage has begun to return to pre-COVID-19 pandemic patterns. We have not experienced a significant impact on total retail sales as a result of the COVID-19 pandemic.

Regulatory Matters

We are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2020 Annual Report on Form 10-K and new regulatory matters occurring in 2021.

2020 Rate Order

In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.

Provisions of the 2020 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $58 million over test year retail revenues;

•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%; and

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

In addition, the 2020 Rate Order established a second phase of our rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In January 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. We cannot predict the timing or outcome of these proceedings.

2019 FERC Rate Case

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

Provisions of the order include, but are not limited to:

•replacing our 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. In February 2021, a Presiding Judge was appointed to continue the formula rate case proceeding after the settlement procedures resulted in an impasse. All rates charged under the revised OATT pursuant to the FERC order are subject to refund until the proceeding concludes. We reserved $21 million as of June 30, 2021, and $15 million as of December 31, 2020, of wholesale revenues in Current Liabilities—Regulatory Liabilities

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on the Condensed Consolidated Balance Sheets. We cannot predict the outcome of the proceedings.

Other FERC Matters

On January 29, 2021, the FERC notified TEP that it is commencing an audit that is intended to evaluate our compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit will cover the period of January 1, 2018 to the present. We cannot predict the outcome or findings, if any, of the FERC audit at this time.

Generation Resource Strategy

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 includes a goal of reducing our carbon dioxide emissions by 80% compared to levels in 2005 by 2035. To achieve this goal, we plan to 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 plan to exit all ownership interests in coal generation facilities over the next 11 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 2020 IRP is dependent on obtaining regulatory recovery approval in future separate proceedings.

Renewable Energy Projects

In 2019, we entered into a BTA to develop Oso Grande. In May 2021, Oso Grande was placed in service, adding approximately 250 MW of wind-powered electric generation, increasing our total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 600 MW. As of June 30, 2021, there was $437 million in costs related to Oso Grande in Plant in Service on the Condensed Consolidated Balance Sheets, of which $388 million and $33 million related to the BTA and AFUDC, respectively.

We enter into long-term renewable PPAs which require us to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. In April 2021, a 100 MW facility, which is accompanied by 30 MW of battery storage, achieved commercial operation. The PPA expires in April 2041.

We are planning to provide more than 70% of our power from wind and solar resources by 2035 as part of our cleaner energy portfolio. The Oso Grande project and renewable PPAs provide a significant shift towards renewable generation and further decrease our dependency on coal-fired generation.

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 discussed draft rules related to retail electric competition. The ACC discussed those draft rules during workshops, but such rules have not been officially proposed and no changes have been made.

In December 2020, ACC staff issued a Notice of Proposed Rulemaking based on energy rules approved by the ACC in November 2020. In June 2021, these rules were modified by amendments and sent back through the formal rulemaking process. If adopted, the new rules would require us to: (i) reduce carbon emissions below a baseline level of 50% by 2032, 65% by 2040, 80% by 2050, 95% by 2060, and 100% by 2070; (ii) include a demand-side resource capacity of at least 35% of our 2020 peak demand by 2030; (iii) achieve on average 1.3% annual energy efficiency savings starting in 2021; and (iv) install energy storage systems with an aggregate capacity equal to at least 5% of our 2020 peak demand. The new rules would repeal the existing RES and EE Standards. We would seek the ACC's approval to recover any costs related to new energy policies or requirements. We cannot predict the outcome of these matters or their impact on our financial position or results of operations.

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Service Disconnection Moratorium

In 2019, the ACC enacted the Summer Moratorium. The Summer Moratorium has remained in effect for 2020 and 2021 to date and will remain in effect each year until the ACC permanently adopts new rules regarding electric service disconnections. In May 2021, ACC staff issued a Notice of Proposed Rulemaking for disconnection rules preliminarily approved by the ACC. If adopted, these rules would require us to choose to suspend disconnections either: (i) when temperatures are forecasted to be less than 32 degrees or more than 95 degrees Fahrenheit; or (ii) during the period from June 1 through October 15 each year. We cannot predict the outcome of these matters or their impact on our financial position or results of operations.

Production Tax Credits

PTCs 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 for 2021 is $0.025 per kWh generated. Oso Grande began generating power to serve our customers in May 2021; the Company began earning PTCs at that time. Oso Grande is estimated to generate approximately $13 million and $25 million in PTCs in 2021 and 2022, respectively. The PTCs are anticipated to offset most of the operating and interest expenses of Oso Grande, which are not currently in base rates.

Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, the project’s electricity generation and associated PTCs may be substantially different than forecasted.

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 and fourth quarters 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 2020 Annual Report on Form 10-K and Part I, Item 3 of this Form 10-Q for information regarding interest rate risk and its impact on earnings.

RESULTS OF OPERATIONS

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

•Cost Recovery Mechanisms — TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, Renewable Energy Standard Tariff, DSM, and TEAM 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 Salt River Project Agricultural Improvement and Power District, 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 2021 compared with the same periods in 2020 presented on a pre-tax basis.

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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)	2021		2020		Percent		2021		2020		Percent
Operating Revenues
Retail	$	297	$	265	12.1	%	$	512	$	457	12.0	%
Wholesale, Long-Term	10		7		42.9	%	20		14		42.9	%
Wholesale, Short-Term (1)	41		25		64.0	%	91		54		68.5	%
Transmission	9		6		50.0	%	20		13		53.8	%
Springerville Units 3 and 4 Participant Billings	20		18		11.1	%	51		38		34.2	%
Other	16		19		(15.8)	%	34		42		(19.0)	%
Total Operating Revenues	$	393	$	340	15.6	%	$	728	$	618	17.8	%

(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 $393 million in the second quarter of 2021 compared with $340 million in the same period for 2020. The increase of $53 million, or 16%, was primarily due to:

•$32 million in higher retail revenue primarily due to: (i) an increase in rates as approved in the 2020 Rate Order; (ii) favorable weather; and (iii) higher RES cost recoveries as a result of higher program expenses;

•$20 million in higher wholesale short-term sales primarily due to an increase in price and sales volume;

•$3 million in higher wholesale long-term sales primarily due to an increase in sales volume;

•$3 million in higher transmission revenue primarily due to an increase in sales volume; and

•$2 million in higher participant billings related to Springerville Units 3 and 4.

The increase was partially offset by:

•$3 million in lower other revenue due to a decrease in LFCR revenues as a result of a rate adjustment as approved in the 2020 Rate Order; partially offset by a natural gas transportation asset management agreement entered into in 2020; and

•$4 million in lower gains from wholesale transactions.

TEP reported Operating Revenues of $728 million in the first six months of 2021 compared with $618 million in the same period for 2020. The increase of $110 million, or 18%, was primarily due to:

•$55 million in higher retail revenue primarily due to: (i) an increase in rates as approved in the 2020 Rate Order; (ii) favorable weather; (iii) higher RES cost recoveries as a result of higher program expenses; and (iv) higher fuel and purchase power recoveries due to higher rates;

•$41 million in higher wholesale short-term sales primarily due to an increase in price and sales volume;

•$13 million in higher participant billings related to Springerville Units 3 and 4;

•$7 million in higher transmission revenue primarily due to an increase in sales volume;

•$6 million in higher wholesale long-term sales primarily due to an increase in sales volume; and

•$3 million in higher other revenue due to a natural gas transportation asset management agreement entered into in 2020.

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The increase was partially offset by:

•$13 million in lower other revenue due to a decrease in LFCR revenues as a result of a rate adjustment as approved in the 2020 Rate Order; and

•$4 million in lower gains from wholesale transactions.

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)	2021	2020	Percent		2021	2020	Percent
Electric Sales (kWh) (1)
Retail Sales	2,340	2,298	1.8	%	4,108	4,098	0.2	%
Wholesale, Long-Term (2)	174	76	128.9	%	311	148	110.1	%
Wholesale, Short-Term	1,176	1,102	6.7	%	2,772	2,348	18.1	%
Total Electric Sales	3,690	3,476	6.2	%	7,191	6,594	9.1	%

Average Revenue Per kWh (3)
Retail	12.70	11.53	10.1	%	12.47	11.15	11.8	%
Wholesale, Long-Term	5.87	8.51	(31.0)	%	6.35	9.25	(31.4)	%
Wholesale, Short-Term	3.46	1.87	85.0	%	3.26	2.10	55.2	%

Total Retail Customers (4)					436,924	432,129	1.1	%

(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)Increase in sales volume is primarily due to an increase in sales to certain long-term wholesale customers.

(3)This metric represents the amount 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.

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

Operating Expenses

Fuel and Purchased Power Expense

TEP reported Fuel and Purchased Power expense of $139 million in the second quarter of 2021 compared with $110 million in the same period for 2020. The increase of $29 million, or 26%, was primarily due to:

•$22 million in higher purchased power primarily due to: (i) an increase in price as a result of higher than normal temperatures; and (ii) a tolling PPA entered into in June 2021;

•$18 million in higher fuel costs primarily due to an increase in natural gas and coal prices, net of realized gains on natural gas swaps; and

•$4 million in higher transmission costs due to: (i) an increase in transmission purchases related to Oso Grande; and (ii) an increase in volume due to higher than normal temperatures during the second quarter of 2021.

The increase was partially offset by a $14 million decrease in expense due to higher PPFAC eligible costs, which exceeded PPFAC recoveries, and were deferred as a regulatory asset.

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TEP reported Fuel and Purchased Power expense of $258 million in the first six months of 2021 compared with $201 million in the same period for 2020. The increase of $57 million, or 28%, was primarily due to:

•$45 million in higher fuel costs primarily due to: (i) an increase in natural gas prices, net of realized gains on gas swaps as a result of a severe winter storm in the southwestern United States in February 2021; and (ii) a net increase in volume;

•$35 million in higher purchased power primarily due to: (i) an increase in price as a result of higher than normal temperatures during the second quarter of 2021; and (ii) a tolling PPA entered into in June 2021; and

•$7 million in higher transmission costs due to: (i) an increase in transmission purchases related to Oso Grande; and (ii) an increase in volume due to higher than normal temperatures during the second quarter of 2021.

The increase was partially offset by a $30 million decrease in expense due to higher PPFAC eligible costs, which exceeded PPFAC recoveries, and were deferred as a regulatory asset.

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)	2021	2020	Percent		2021	2020	Percent
Sources of Energy
Coal-Fired Generation	972	1,126	(13.7)	%	2,456	2,535	(3.1)	%
Gas-Fired Generation	1,967	1,843	6.7	%	3,575	3,319	7.7	%
Utility-Owned Renewable Generation (1)	338	25	*		357	45	*
Total Generation	3,277	2,994	9.5	%	6,388	5,899	8.3	%
Purchased Power, Non-Renewable	381	409	(6.8)	%	593	579	2.4	%
Purchased Power, Renewable (2)	306	217	41.0	%	492	368	33.7	%
Total Generation and Purchased Power (3)	3,964	3,620	9.5	%	7,473	6,846	9.2	%


(cents per kWh)
Average Fuel Cost of Generated Power (4)
Coal	2.86	2.53	13.0	%	2.47	2.53	(2.4)	%
Natural Gas (5) (6)	2.63	1.82	44.5	%	3.05	1.81	68.5	%
Average Cost of Purchased Power (7)
Purchased Power, Non-Renewable (6)	8.05	3.11	158.8	%	7.59	2.96	156.4	%
Purchased Power, Renewable	7.49	9.49	(21.1)	%	7.95	9.42	(15.6)	%

*Not meaningful

(1)In May 2021, Oso Grande was placed in service, adding 250 MW of wind-powered electric generation, increasing TEP's total utility-owned renewable generation.

(2)In April 2021, a 100 MW facility achieved commercial operation, adding up to 100 MW of renewable purchased power capacity for TEP under the related PPA.

(3)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.

(4)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 to analyze the performance of generation stations.

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

(6)In February 2021, a severe winter storm in the southwestern United States drove increased energy demand, limited the availability of natural gas to fuel generation stations, and increased the cost of natural gas and purchased power. In June 2021, the market price for purchased power increased significantly due to high demand resulting from higher than normal temperatures.

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(7)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 $95 million in the second quarter of 2021 compared with $84 million in the same period for 2020. The increase of $11 million, or 13%, was primarily due to:

•$8 million in higher maintenance expense related to planned generation outages in 2021; and

•$3 million in higher employee benefits expense.

TEP reported Operations and Maintenance expense of $206 million in the first six months of 2021 compared with $171 million in the same period for 2020. The increase of $35 million, or 20%, was primarily due to:

•$16 million in higher reimbursable maintenance expense related to Springerville Units 3 and 4 planned generation outages in 2021;

•$12 million in higher maintenance expense related to planned generation outages in 2021; and

•$7 million in higher employee wages and benefits expense.

Depreciation and Amortization Expense

TEP reported Depreciation and Amortization expense of $60 million in the second quarter of 2021 compared with $54 million in the same period for 2020. The increase of $6 million, or 11%, was primarily due to:

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

•$3 million in higher depreciation and amortization expense due to an increase in depreciation rates and amortization as approved in the 2020 Rate Order.

TEP reported Depreciation and Amortization expense of $119 million in the first six months of 2021 compared with $108 million in the same period for 2020. The increase of $11 million, or 10%, was primarily due to:

•$7 million in higher depreciation and amortization expense due to an increase in asset base; and

•$4 million in higher depreciation and amortization expense due to an increase in depreciation rates and amortization as approved in the 2020 Rate Order.

Other Income (Expense)

TEP reported other expense of $12 million in the second quarter of 2021 compared with $9 million in the same period for 2020. The increase of $3 million, or 33%, was primarily due to:

•$2 million in lower AFUDC due to a 2020 FERC Order that provided for an adjustment in the AFUDC calculation not recurring in 2021; and

•$2 million decrease in the value of investments used to support certain post-employment benefits as a result of less favorable market conditions.

The increase was partially offset by a $1 million increase in other income due to an increase in expected return on pension plan assets.

TEP reported other expense of $18 million in the first six months of 2021 compared with $29 million in the same period for 2020. The decrease of $11 million, or 38%, was primarily due to:

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

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

•$1 million in higher AFUDC as a result of a change in the AFUDC rate.

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Income Tax Expense

TEP reported Income Tax Expense of $8 million in the second quarter of 2021 compared with $11 million in the same period for 2020, a decrease of $3 million, or 27%. The decrease was primarily due to a $4 million increase in PTCs. The decrease was partially offset by $1 million in higher tax expense due to an increase in taxable earnings.

TEP reported Income Tax Expense of $10 million in the first six months of 2021 compared with $14 million in the same period for 2020. The decrease of $4 million, or 29%, was primarily due to:

•$6 million increase in PTCs; and

•$2 million decrease in EDIT amortization.

The decrease was partially offset by $4 million in higher tax expense due to an increase in taxable earnings.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

An extended period of economic disruption could affect our business and financial conditions, and access to sources of liquidity. 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 under the 2015 Credit Agreement as needed to fund our business activities. We believe that we have sufficient liquidity under our revolving credit agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.

Available Liquidity


(in millions)	June 30, 2021
Cash and Cash Equivalents	$	336
Amount Available under Revolving Credit Agreement (1)	240
Total Liquidity	$	576

(1)The 2015 Credit Agreement provides for $250 million of revolving credit commitments with a LOC sub-limit 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; (iii) employee benefit obligations; and (iv) contracted obligations including those forecasted in the Capital Expenditures table reported in our 2020 Annual Report on Form 10-K.

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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)	2021		2020		Percent
Operating Activities	$	168	$	188	(10.6)	%
Investing Activities	(265)		(506)		(47.6)	%
Financing Activities	370		368		0.5	%
Net Increase	273		50		*
Beginning of Period	82		28		192.9	%
End of Period	$	355	$	78	355.1	%

* Not meaningful

Operating Activities

In the first six months of 2021, net cash flows from operating activities decreased by $20 million compared with the same period in 2020. The decrease was primarily due to: (i) changes in working capital related to higher fuel costs and purchased power market prices and the timing of billing collections; and (ii) higher operations and maintenance expenses due to an increase in employee wages and benefits expense and planned generation outages in 2021.

The decrease was partially offset by: (i) higher retail revenues related to an increase in rates as approved in the 2020 Rate Order; and (ii) higher transmission revenues due to an increase in volumes.

Investing Activities

In the first six months of 2021, net cash flows used for investing activities decreased by $241 million compared with the same period in 2020 primarily due to higher capital expenditures related to Oso Grande BTA payments in 2020 not occurring in 2021.

Financing Activities

In the first six months of 2021, net cash flows from financing activities increased by $2 million compared with the same period in 2020 primarily due to lower repayments from credit facility borrowings.

The increase was partially offset by: (i) a decrease in equity contributions from UNS Energy; and (ii) lower debt and credit facility proceeds.

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, 2021, TEP's short-term investments included highly-rated and liquid money market funds.

Access to Credit Agreements

We have access to working capital through our credit agreements.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2020 Annual Report on Form 10-K for additional information regarding our credit agreements.

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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 May 2021, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2051, with the proceeds to be used to redeem debt in August 2021 and for general corporate purposes. On July 20, 2021, TEP issued a revocable notice to redeem $250 million aggregate principal amount of 5.15% senior unsecured notes at par on August 20, 2021. These notes have a maturity date of November 15, 2021.

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 repurchase debt in the future. We anticipate redeeming the $250 million aggregate principal amount of 5.15% senior unsecured notes due November 15, 2021 in the third quarter of 2021.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of June 30, 2021, 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, 2021, 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.

Contributions from Parent

TEP received equity contributions of $50 million from UNS Energy in the second quarter and first six months of 2021 and received equity contributions of $50 million and $200 million in the second quarter and first six months of 2020, respectively.

Dividends Paid to Parent

TEP did not declare or pay dividends to UNS Energy in the second quarter or first six months of 2021 or 2020. On July 26, 2021, TEP declared and paid a $38 million dividend to UNS Energy.

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, 2021, TEP had $24 million of cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities. As of July 28, 2021, there was $19 million of cash posted as collateral to provide credit enhancement.

Capital Expenditures

TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In the first six months of 2021, there were no material changes to capital expenditures as reported in our 2020 Annual Report on Form 10-K.

Income Tax Position

TEP made net tax sharing payments of $3 million to UNS Energy in the first six months of 2021. Based on our remaining tax credit carryforward balances and limitations on their use in individual years, we expect to make additional tax sharing payments

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in 2021. Future payment obligations are subject to change and are not expected to have a significant impact on our operating cash flows.

Payroll Tax

In response to the COVID-19 pandemic, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was signed into law on March 27, 2020. As permitted by the CARES Act, TEP deferred payment of the employer's portion of social security taxes. In 2020, TEP recorded total deferred deposits of $7 million in Accrued Taxes Other than Income Taxes and Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. TEP expects the total deferred deposits to 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 (NOx), 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 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. The regulatory deadline for ADEQ to submit the revised SIP to the EPA for approval is July 31, 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 ADEQ submits the revised SIP to the EPA. TEP cannot predict the outcome of these matters at this time, but will continue to work with the agency to determine compliance strategies as needed.

Greenhouse Gas Regulation

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

In June 2019, the EPA repealed the CPP and issued the Affordable Clean Energy (ACE) rule, establishing new emission guidelines for existing coal-fired generation facilities 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.

On March 5, 2021, the U.S. Court of Appeals for the D.C. Circuit issued a mandate vacating and remanding the ACE rule to the EPA. The mandate also vacated amendments that extended the timeline under which companies had to come into compliance with the rule.

TEP cannot predict the outcome of these matters at this time, but will continue to monitor legal challenges, legislative efforts, and administrative rulemakings.

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Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring the 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. APS, the operating agent of Four Corners, began an assessment of corrective measures in 2019, and expects the assessment to continue through 2021.

Since these regulations were finalized, the EPA has taken steps to modify this rule. The following are pending rulemakings:

•In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act, which gave the EPA authority to either authorize states to establish their own permit program under RCRA for implementing regulation of CCR or issue federal permits in states without a program and on tribal lands. In accordance with this Act, the EPA proposed to establish a federal CCR permit program on February 20, 2020. Public comment on the EPA's proposal closed in August 2020.

•On March 15, 2018, the EPA proposed to add boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. In a separate proposal dated August 14, 2019, the EPA acknowledged that if it finalizes the addition of boron it will need to establish an alternative risk-based groundwater protection standard for boron, as boron does not have a Maximum Contaminant Level. TEP cannot predict the outcome or timing on when the EPA will take final action on this matter.

As of June 30, 2021, the EPA has not taken final action on these proposals. As a result, TEP cannot predict the impact of the proposed rulemakings.

Effluent Limitation Guidelines

In 2015, as part of the Clean Water Act, the EPA published the final Steam Electric Power Generating category Effluent Limitation Guidelines and Standard rule, revising standards and limitations for coal-fired generation wastewater discharges. The rule established new or additional Effluent Limitations Guidelines (ELG) for wastewater discharges associated with fly ash, bottom ash, flue gas desulfurization, flue gas mercury control, and gasification of fuels such as coal and petroleum coke. In response to legal challenges, the EPA revised the ELGs and issued a final rule on August 31, 2020, which became effective December 14, 2020. The final rule revised requirements for flue gas desulfurization wastewater and bottom ash transport water.

With the exception of Four Corners, none of TEP's coal-fired generation facilities are subject to the final rule. The revised ELGs warrant a modification of Four Corners' wastewater discharge permit, or National Pollution Discharge Elimination System permit, which was last issued in September 2019. APS filed a permit modification request on January 11, 2021, which is still pending EPA response. TEP does not anticipate a material impact on operations or financial results.

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, 2021, 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 2020 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.

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2020 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures were effective as of June 30, 2021. There was no change in TEP’s internal control over financial reporting during the quarter ended June 30, 2021, 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 2020 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 2020 Annual Report on Form 10-K.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.

Description

31(a)

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Susan M. Gray

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, 2021, 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 28, 2021	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President, Chief Financial Officer, and Director
		(Principal Financial Officer)