tep-20220930

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 September 30, 2022

☐ 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 October 27, 2022.

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			21
Critical Accounting Estimates			35
New Accounting Standards Issued and Not Yet Adopted			36
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



2019 FERC Rate Order						In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019

2020 IRP						TEP's 2020 Integrated Resource Plan which calls for TEP to reduce its carbon emissions by 80% and to supply more than 70% of its energy to retail customers from renewable resources by 2035

2021 Credit Agreement						The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026
2022 Rate Case						In June 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021

ACC						Arizona Corporation Commission

ADEQ						Arizona Department of Environmental Quality
AFUDC						Allowance for Funds Used During Construction




COVID-19						Coronavirus Disease 2019
DG						Distributed Generation
DSM						Demand Side Management

ECA						Environmental Compliance Adjustor
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
Phase 2						In 2020, the ACC issued a rate order for new rates and 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
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

TCA						Transmission Cost Adjustor


TEAM						Tax Expense Adjustor Mechanism

ENTITIES AND GENERATING STATIONS


APS						Arizona Public Service Company
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


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

Springerville						Springerville Generating Station

Sundt						H. Wilson Sundt Generating Station

iii


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 2021 Annual Report on Form 10-K/A; 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, inclusive of the Inflation Reduction Act of 2022, and energy policies and the adoption of new regulations regarding electric service disconnections; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies; and/or changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output, or accelerate generation facility retirements; the outcome of Phase 2; the outcome of the 2022 Rate Case; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality and extreme weather events affecting electricity usage of our customers and the performance of our operations; 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 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, including inflationary effects; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting estimates; the ongoing impact of mandated energy efficiency and DG initiatives; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other cyberspace attacks to our information security and our operations and technology infrastructure, including attacks that may rise from heightened geopolitical instability; the performance of generation facilities, including renewable generation resources; the extent of the impact of the COVID-19 pandemic or other global health crises on our business and operations, and the economic and societal disruptions resulting there from the 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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Operating Revenues	$	587,262	$	507,584	$	1,363,515	$	1,235,788

Operating Expenses
Fuel	147,246		120,972		336,020		292,627
Purchased Power	89,709		87,943		173,740		169,762
Transmission and Other PPFAC Recoverable Costs	26,566		19,780		64,312		49,341
Decrease to Reflect PPFAC Recovery Treatment	(4,924)		(25,108)		(19,170)		(50,068)
Total Fuel and Purchased Power	258,597		203,587		554,902		461,662
Operations and Maintenance	97,874		94,771		296,444		300,865
Depreciation	55,039		51,744		163,087		149,200
Amortization	10,294		10,800		30,151		31,971
Taxes Other Than Income Taxes	15,966		15,210		47,930		46,004
Total Operating Expenses	437,770		376,112		1,092,514		989,702

Operating Income	149,492		131,472		271,001		246,086

Other Income (Expense)
Interest Expense	(21,304)		(22,774)		(63,938)		(66,970)
Allowance For Borrowed Funds	614		978		2,026		5,579
Allowance For Equity Funds	1,874		2,635		5,915		14,737
Unrealized Gains (Losses) on Investments	(1,794)		(350)		(8,515)		3,205
Other, Net	4,611		1,934		11,033		7,504
Total Other Income (Expense)	(15,999)		(17,577)		(53,479)		(35,945)

Income Before Income Tax Expense	133,493		113,895		217,522		210,141
Income Tax Expense	14,196		17,027		23,831		26,979
Net Income	$	119,297	$	96,868	$	193,691	$	183,162

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)


	Nine Months Ended September 30,
	2022		2021
Cash Flows from Operating Activities
Net Income	$	193,691	$	183,162
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	163,087		149,200
Amortization Expense	30,151		31,971

Amortization of Debt Issuance Costs	2,241		2,141
Use of Renewable Energy Credits for Compliance	34,380		35,762
Deferred Income Taxes	23,853		23,782

Pension and Other Postretirement Benefits Expense	8,735		11,506
Pension and Other Postretirement Benefits Funding	(15,701)		(15,391)

Allowance for Equity Funds Used During Construction	(5,915)		(14,737)


Change in Long-Term Regulatory Assets and Liabilities	45,005		13,492

Changes in Current Assets and Current Liabilities:
Accounts Receivable	(160,267)		(74,525)
Materials, Supplies, and Fuel Inventory	6,097		(18,634)
Regulatory Assets	(54,019)		(41,638)

Other Current Assets	(3,926)		(6,324)
Accounts Payable and Accrued Charges	168,928		74,242

Income Taxes Receivable/Payable	(1,490)		1,095
Regulatory Liabilities	1,184		(9,157)
Other, Net	1,736		(3,258)
Net Cash Flows—Operating Activities	437,770		342,689
Cash Flows from Investing Activities
Capital Expenditures	(296,014)		(360,374)



Purchase Intangibles, Renewable Energy Credits	(49,728)		(42,267)

Other Investments	2,517		—
Contributions in Aid of Construction	6,495		4,360

Net Cash Flows—Investing Activities	(336,730)		(398,281)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	5,000		35,000
Repayments of Borrowings, Revolving Credit Facility	(20,000)		(35,000)


Proceeds from Issuance, Long-Term Debt—Net of Discount	323,804		322,231
Repayments of Long-Term Debt	(193,465)		(250,000)
Dividends Paid to Parent	(75,000)		(37,500)


Contribution from Parent	—		50,000
Other, Net	2,457		(1,645)
Net Cash Flows—Financing Activities	42,796		83,086
Net Increase in Cash, Cash Equivalents, and Restricted Cash	143,836		27,494
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	33,489		82,003
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	177,325	$	109,497

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	September 30, 2022		December 31, 2021
ASSETS
Utility Plant
Plant in Service	$	7,737,100	$	7,797,935

Construction Work in Progress	217,896		320,931
Total Utility Plant	7,954,996		8,118,866
Accumulated Depreciation and Amortization	(2,592,314)		(2,786,839)

Total Utility Plant, Net	5,362,682		5,332,027

Investments and Other Property	70,831		81,958

Current Assets
Cash and Cash Equivalents	153,269		9,970
Accounts Receivable (Net of Allowance for Credit Losses of $8,978 and $10,044)	356,887		192,579
Fuel Inventory	18,395		26,971
Materials and Supplies	146,886		141,677
Regulatory Assets	162,118		116,442
Derivative Instruments	43,461		19,406

Other	23,013		24,229
Total Current Assets	904,029		531,274
Regulatory and Other Assets
Regulatory Assets	229,932		267,669
Derivative Instruments	86,077		14,392
Other	113,749		94,420
Total Regulatory and Other Assets	429,758		376,481
Total Assets	$	6,767,300	$	6,321,740

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	September 30, 2022		December 31, 2021
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2022 and December 31, 2021)	$	1,696,539	$	1,696,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	969,633		850,942
Accumulated Other Comprehensive Loss	(9,324)		(9,915)
Total Common Stock Equity	2,650,491		2,531,209
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2022 and December 31, 2021)	—		—

Long-Term Debt, Net	2,114,505		2,134,534
Total Capitalization	4,764,996		4,665,743
Current Liabilities
Current Maturities of Long-Term Debt, Net	149,915		—
Borrowings Under Credit Agreement	—		15,000

Accounts Payable	233,782		139,329
Accrued Taxes Other than Income Taxes	82,568		53,534
Accrued Employee Expenses	35,015		36,217
Accrued Interest	19,632		16,265
Regulatory Liabilities	134,795		111,356
Customer Deposits	13,708		12,791
Derivative Instruments	6,632		15,854
Other	56,497		25,358
Total Current Liabilities	732,544		425,704
Regulatory and Other Liabilities
Deferred Income Taxes, Net	577,750		548,750
Regulatory Liabilities	382,590		352,226
Pension and Other Postretirement Benefits	108,152		120,020
Derivative Instruments	384		3,848
Other	200,884		205,449
Total Regulatory and Other Liabilities	1,269,760		1,230,293

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	6,767,300	$	6,321,740

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 June 30, 2021	$	1,696,539	$	(6,357)	$	798,491	$	(10,504)	$	2,478,169
Net Income					96,868				96,868
Other Comprehensive Income, Net of Tax							219		219
Dividend Declared to Parent					(37,500)				(37,500)

Balances as of September 30, 2021	$	1,696,539	$	(6,357)	$	857,859	$	(10,285)	$	2,537,756


Balances as of June 30, 2022	$	1,696,539	$	(6,357)	$	925,336	$	(9,521)	$	2,605,997
Net Income					119,297				119,297
Other Comprehensive Income, Net of Tax							197		197
Dividends Declared to Parent					(75,000)				(75,000)


Balances as of September 30, 2022	$	1,696,539	$	(6,357)	$	969,633	$	(9,324)	$	2,650,491


	Nine Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2020	$	1,646,539	$	(6,357)	$	712,197	$	(10,942)	$	2,341,437
Net Income					183,162				183,162
Other Comprehensive Income, Net of Tax							657		657
Dividend Declared to Parent					(37,500)				(37,500)

Contribution from Parent	50,000								50,000
Balances as of September 30, 2021	$	1,696,539	$	(6,357)	$	857,859	$	(10,285)	$	2,537,756


Balances as of December 31, 2021	$	1,696,539	$	(6,357)	$	850,942	$	(9,915)	$	2,531,209
Net Income					193,691				193,691
Other Comprehensive Income, Net of Tax							591		591
Dividends Declared to Parent					(75,000)				(75,000)


Balances as of September 30, 2022	$	1,696,539	$	(6,357)	$	969,633	$	(9,324)	$	2,650,491

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 442,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of 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 2021 Annual Report on Form 10-K/A.

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 September 30, 2022, 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.

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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:


	September 30,
(in millions)	2022		2021
Cash and Cash Equivalents	$	153	$	90
Restricted Cash included in:
Investments and Other Property	21		17
Current Assets—Other	3		2
Total Cash, Cash Equivalents, and Restricted Cash	$	177	$	109

Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan.

Income Tax Expense

TEP realized PTC benefits of $11 million and $19 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2022, respectively, and $2 million and $8 million for the three and nine months ended September 30, 2021, respectively, as a result of Oso Grande being placed in service in May 2021.

Asset Retirement Obligations

The following table reconciles the beginning and ending aggregate carrying amounts of Asset Retirement Obligation (ARO) accruals included in Other on the Condensed Consolidated Balance Sheets:


(in millions)	September 30, 2022		December 31, 2021
Beginning of Period	$	139	$	96
Liabilities Incurred (1)	1		14
Liabilities Settled (2)	(2)		(2)
Regulatory Deferral	3		4
Revisions to the Present Value of Estimated Cash Flows (3)	(16)		27
End of Period	$	125	$	139

(1)In 2021, TEP incurred an ARO for Oso Grande. In 2022, TEP incurred an ARO for new photovoltaic generation placed in service.

(2)Primarily related to the retirement of Navajo.

(3)Primarily related to revised decommissioning estimates for San Juan.

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 the Company'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

2022 Rate Case

In June 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021.

TEP's key 2022 Rate Case proposals are described below:

•a $136 million net increase in retail revenues comprised of the following components:

◦a non-fuel retail revenue increase of $159 million over test year non-fuel retail revenues;

◦a $66 million increase in fuel-related retail revenues, offset by a $71 million reduction in PPFAC revenues; and

◦changes in certain adjustor mechanisms, including DSM, ECA, and RES, that result in an $18 million reduction in revenues to be collected from customers.

•a 7.31% return on original cost rate base of $3.6 billion, which includes a cost of equity of 10.25% and an average cost of debt of 3.82%; and

•a new Resource Transition Mechanism adjustor that is designed to provide more timely recovery of TEP's clean energy investments and replace the ECA.

TEP requested new rates to be implemented by September 1, 2023. TEP cannot predict the timing or outcome of this proceeding.

2020 ACC Phase 2 Proceedings

In 2020, the ACC issued a rate order for new rates and 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 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. In January 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. TEP cannot predict the timing or outcome of these proceedings.

2019 FERC Rate Order

In 2019, TEP filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more timely recovery of transmission-related costs. The FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the 2019 FERC Rate Order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.

Provisions of the settlement agreement include, but are not limited to:

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

•a 9.79% 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.

Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. As of July 2022, TEP had returned all amounts in excess of the rates approved in the settlement agreement previously deferred as a regulatory liability. TEP had no wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets as of September 30, 2022, and $15 million as of December 31, 2021, related to the 2019 FERC Rate Order.

OTHER FERC MATTERS

In January 2021, the FERC notified TEP that it was commencing an audit with the intent 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 covers the period of January 1, 2018, to December 31, 2021. In September 2022, TEP received a draft audit report and responded to the recommendations and findings

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in the report on October 17, 2022. TEP is awaiting the final audit report and does not expect a material financial impact from the report.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for 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 allows for reconciliation of differences between actual costs and those recovered in the preceding period. In April 2022, the ACC approved a rate adjustment for the PPFAC that sets the true-up component of the PPFAC rate to recover the existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which may result in future under-collection of PPFAC costs.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Beginning of Period	$	103	$	47	$	91	$	23
Deferred Fuel and Purchased Power Costs (1)	116		119		269		269
PPFAC and Base Power Recoveries (2)	(109)		(94)		(250)		(220)
End of Period	$	110	$	72	$	110	$	72

(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. The 2022 PPFAC rate adjustment became effective on April 29, 2022.

Tax Expense Adjustor Mechanism

The TEAM allows for the timely recovery of future significant income tax changes and provides the Company the ability to pass through as a kWh surcharge: (i) the change in excess deferred income taxes compared to the test year; and (ii) the income tax effects of tax legislation that materially impacts TEP's 2018 test year revenue requirements.

Transmission Cost Adjustor

The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January of each year.

In February 2022, the ACC approved TEP's motion to modify the TCA plan of administration to reflect the terms of the 2019 FERC Rate Order settlement agreement.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2022 is 12% of retail electric sales. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES surcharge.

In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 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. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal to phase out the RES tariff. In June 2022, TEP filed a request with the ACC for approval of an extension of the 2021 RES implementation plan through the completion of the 2022 Rate Case. The rate case includes a proposal to transition away from the current RES surcharge and to recover the costs in base rates.

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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.

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 Standards. The 2018 plan has been effective from 2018 through the present and will remain in effect until another plan is approved. In 2021, TEP filed its 2022 energy efficiency implementation plan with a budget of $23 million. In June 2022, TEP filed a supplement to the 2022 energy efficiency implementation plan with the ACC to include a new pilot plan, which increases the budget of the plan to $24 million. The 2022 Rate Case includes a proposal to transition away from the current DSM surcharge and to recover the costs in base rates. TEP cannot predict the outcome of these proceedings.

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. 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.

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REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below:


($ in millions)	Remaining Recovery Period (years)	September 30, 2022		December 31, 2021
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	124	$	128
Under Recovered Purchased Energy Costs	2	110		91
Early Generation Retirement Costs (1)	Various	61		38
Property Tax Deferrals (2)	1	28		27
Lost Fixed Cost Recovery	1	23		37
Final Mine Reclamation and Retiree Healthcare Costs (3)	6	17		17
Income Taxes Recoverable through Future Rates (4)	Various	7		17

Unamortized Loss on Reacquired Debt	Various	5		5
Springerville Unit 1 Leasehold Improvements (5)	1	2		4

Derivatives (Note 9)	7	—		8
Other Regulatory Assets	Various	15		12
Total Regulatory Assets		392		384
Less Current Portion	1	162		116
Total Non-Current Regulatory Assets		$	230	$	268


Regulatory Liabilities
Income Taxes Payable through Future Rates (4)	Various	$	245	$	268
Derivatives (Note 9)	7	117		19
Renewable Energy Standard	Various	72		66
Net Cost of Removal (6)	Various	43		73
Demand Side Management	1	20		12
Transmission Cost Adjustor	1	10		9
Deferred Investment Tax Credits	Various	9		1

Transmission Revenue Subject to Refund—FERC	1	1		15
Other Regulatory Liabilities	Various	1		—



Total Regulatory Liabilities		518		463
Less Current Portion	1	135		111
Total Non-Current Regulatory Liabilities		$	383	$	352

(1)Increase in Early Generation Retirement Costs is primarily due to the San Juan Unit 1 retirement in June 2022.

(2)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes.

(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. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022.

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

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

(6)Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. The decrease in Net Cost of Removal is primarily due to San Juan Unit 1 being retired in June 2022.

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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 June 2022, San Juan Unit 1 was retired by Public Service Company of New Mexico (PNM), the operator of San Juan. Contemporaneously, TEP's obligations ceased with respect to: (i) costs related to San Juan Unit 1 and Common Facilities stemming from continued operations at San Juan; and (ii) purchases under the coal supply agreement between PNM and San Juan Coal Company. TEP recovers costs related to its ownership interest in San Juan in base rates and expects to collect the remaining net book value of San Juan by the end of 2022. As of September 30, 2022, there was a balance related to San Juan of $24 million in Regulatory and Other Assets—Regulatory Assets and $15 million in Regulatory and Other Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP requested recovery of unused materials and supplies costs related to San Juan in its 2022 Rate Case.

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 September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Retail	$	376	$	355	$	900	$	867
Wholesale (1)	150		86		305		189
Other Services	30		24		77		85
Revenues from Contracts with Customers	556		465		1,282		1,141
Alternative Revenues	7		5		20		15
Other	24		38		62		80
Total Operating Revenues	$	587	$	508	$	1,364	$	1,236

(1)Pursuant to a FERC order, all rates charged under TEP's revised OATT were subject to refund until the 2019 FERC Rate Order proceedings concluded. Prior to July 2022, wholesale revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Order.

NOTE 4. ACCOUNTS RECEIVABLE

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


(in millions)	September 30, 2022		December 31, 2021
Retail	$	120	$	78
Retail, Unbilled	56		44
Retail, Allowance for Credit Losses	(9)		(10)
Wholesale (1)	120		47
Due from Affiliates (Note 5)	34		17
Other	36		17
Accounts Receivable	$	357	$	193

(1)Includes $42 million as of September 30, 2022, and $16 million as of December 31, 2021, of receivables related to revenue from derivative instruments.

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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 September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Beginning of Period	$	(8)	$	(13)	$	(10)	$	(13)
Credit Loss Expense	(2)		(1)		(3)		(2)
Write-offs	1		1		4		2

End of Period (1)	$	(9)	$	(13)	$	(9)	$	(13)

(1)In 2021, the ACC adopted permanent rules that annually suspend service disconnections and late fees for electric residential customers who otherwise are eligible for service disconnection during the period from June 1 through October 15.

TEP continuously monitors collection activity and adjusts its allowance for credit losses as needed.

Customer Payment Assistance

In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $2 million and $13 million in DES payment assistance funds in the three and nine months ended September 30, 2022, respectively.

NOTE 5. RELATED PARTY TRANSACTIONS

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

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


(in millions)	September 30, 2022		December 31, 2021
Receivables from Related Parties
UNS Electric	$	26	$	8
UNS Energy	7		7
UNS Gas	1		2








Total Due from Related Parties	$	34	$	17

Payables to Related Parties
UNS Energy	$	1	$	1
UNS Electric	2		—



UNS Gas	—		1

Total Due to Related Parties	$	3	$	2

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	1	$	3	$	4	$	9
Wholesale Revenues, UNS Electric (1)	24		16		34		21
Control Area Services, UNS Electric (2)	—		1		2		4
Common Costs, UNS Energy Affiliates (3)	5		6		16		16


Goods and Services Provided by Affiliates to TEP
Wholesale Revenues, UNS Electric (1)	$	1	$	—	$	1	$	1

Corporate Services, UNS Energy (4)	1		1		6		5
Corporate Services, UNS Energy Affiliates (5)	—		1		1		3

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

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

(3)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

(4)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. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $1 million and $5 million for the three and nine months ended September 30, 2022, respectively, and $2 million and $5 million for the three and nine months ended September 30, 2021, respectively.

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

DIVIDENDS DECLARED AND PAID TO PARENT

On October 27, 2022, TEP declared a $25 million dividend to UNS Energy, to be paid on or before December 31, 2022.

NOTE 6. DEBT AND CREDIT AGREEMENTS

There have been no significant changes to TEP's debt or credit agreements from those reported in its 2021 Annual Report on Form 10-K/A, except as noted below.

DEBT

Issuance and Redemptions

In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt and for general corporate purposes.

In March 2022, TEP redeemed at par prior to maturity $177 million in aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.

In June 2022, TEP redeemed at par prior to maturity $16 million in aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.

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CREDIT AGREEMENT

2021 Credit Agreement

As of September 30, 2022, there was $240 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings and a $10 million LOC issued with fees that accrue at a rate of 1.025% per annum. The LOC expires October 2023.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2021 Annual Report on Form 10-K/A.

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 term of the respective coal supply agreement. 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 funded.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $38 million and $40 million as of September 30, 2022, and December 31, 2021, respectively, was recorded in Other on the Condensed Consolidated Balance Sheets. TEP’s share of final mine reclamation costs at Four Corners is estimated to be $8 million upon the expected expiration of the Four Corners coal supply agreement in 2031. On September 30, 2022, TEP’s estimated share of final mine reclamation costs at San Juan was $33 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. For additional information see Note 1, Restricted Cash and Note 2, Plant in Service.

Performance Guarantees

TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, 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 and San Juan 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 September 30, 2022, there have been no such payment defaults under any of the participation agreements.

The Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities.

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

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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. These landfills were in operation from 1959 to 1972 and 1953 to 1962, respectively. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized.

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2022		2021		2022		2021
Service Cost	$	6	$	5	$	1	$	2
Non-Service Cost (1)
Interest Cost	4		3		—		—
Expected Return on Plan Assets	(9)		(8)		—		—
Amortization of Net Loss	1		2		—		—
Net Periodic Benefit Cost	$	2	$	2	$	1	$	2


	Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Service Cost	$	16	$	15	$	4	$	5
Non-Service Cost (1)
Interest Cost	12		10		1		1
Expected Return on Plan Assets	(28)		(25)		(1)		(1)
Amortization of Net Loss	5		7		—		—
Net Periodic Benefit Cost	$	5	$	7	$	4	$	5

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

NOTE 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

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

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FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

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


	Level 1		Level 2		Total
(in millions)	September 30, 2022
Assets
Cash Equivalents (1)	$	75	$	—	$	75
Restricted Cash (1)	24		—		24
Energy Derivative Contracts, Regulatory Recovery (2)	—		123		123
Energy Derivative Contracts, No Regulatory Recovery (2)	—		7		7
Total Assets	99		130		229
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(7)		(7)

Total Liabilities	—		(7)		(7)
Total Assets (Liabilities), Net	$	99	$	123	$	222


(in millions)	December 31, 2021
Assets

Restricted Cash (1)	$	23	$	—	$	23
Energy Derivative Contracts, Regulatory Recovery (2)	—		30		30
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	23		34		57
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(20)		(20)


Total Liabilities	—		(20)		(20)
Total Assets (Liabilities), Net	$	23	$	14	$	37

(1)Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate 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.

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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 (1)
(in millions)	September 30, 2022
Derivative Assets
Energy Derivative Contracts	$	130	$	5	$	26	$	99
Derivative Liabilities
Energy Derivative Contracts	(7)		(5)		—		(2)


(in millions)	December 31, 2021
Derivative Assets
Energy Derivative Contracts	$	34	$	14	$	—	$	20
Derivative Liabilities
Energy Derivative Contracts	(20)		(14)		—		(6)

(1)TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Condensed Consolidated Balance Sheets. As of October 27, 2022, TEP held $13 million of cash received as collateral to provide credit enhancement.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Unrealized Net Gain (Loss) (1)	$	(1)	$	43	$	106	$	56

(1)The change in unrealized net gain (loss) on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas.

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 September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Operating Revenues	$	—	$	6	$	10	$	7

Derivative Volumes

As of September 30, 2022, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:


	September 30, 2022	December 31, 2021
Power Contracts GWh	3,211	2,617
Gas Contracts BBtu	99,384	112,316

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, could 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 $42 million as of September 30, 2022, compared with $26 million as of December 31, 2021. As of September 30, 2022, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on September 30, 2022, TEP would have been required to post $42 million of collateral. As of September 30, 2022, TEP had $45 million in outstanding net payable balances for settled positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below.

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


	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,264	$	2,135	$	1,888	$	2,357

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:


	Nine Months Ended September 30,
(in millions)	2022		2021
Accrued Capital Expenditures	$	25	$	43

Renewable Energy Credits	4		4

Asset Retirement Obligation/Cost Increase (Decrease) (1)	(28)		11
Net Cost of Removal Decrease (2)	(49)		(37)

(1)In 2021, primarily represents a new obligation related to Oso Grande. In 2022, primarily represents the retirement of the San Juan asset retirement cost asset.

(2)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2021, TEP transferred a portion of the Net Cost of Removal recorded in Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of revised depreciation rates. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset.

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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;

•current economic conditions;

•factors affecting results of operations;

•results of operations;

•liquidity and capital resources, including capital expenditures and environmental matters;

•critical accounting 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 2021 Annual Report on Form 10-K/A, 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; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers.

•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. Our goal is to reduce carbon emissions by 80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In May 2022, Fortis set a goal to achieve net-zero direct carbon emissions by 2050. The establishment of this additional target reinforces Fortis' commitment, along with that of its subsidiaries, to decarbonize over the long-term, while preserving customer reliability and affordability. 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

The COVID-19 pandemic caused changes in consumer and business behavior and disrupted economic activity in TEP’s service territory. Our business continuity plans and protocols are intended to support the continued delivery of safe and reliable service to our customers and the communities we serve. As the pandemic abates and conditions evolve, we continue to evaluate and assess protocols and plans and monitor 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.

TEP faces market risks associated with fluctuations in commodity prices, which can temporarily affect the Company’s cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility.

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Performance - The third quarter of 2022 compared with the third quarter of 2021

TEP reported net income of $119 million in the third quarter of 2022 compared with net income of $97 million in the third quarter of 2021. The increase of $22 million, or 23%, was primarily due to:

•$9 million in higher transmission revenue primarily due to the 2019 FERC Rate Order settlement agreement triggering recognition of revenue previously reserved for refund;

•$7 million in higher retail revenue primarily due to higher usage as a result of favorable weather;

•$5 million in lower income tax expense primarily due to an increase in PTCs as a result of Oso Grande, placed in service in May 2021, net of higher tax expense due to an increase in taxable earnings; and

•$3 million in lower base operations and maintenance expenses primarily due to the shutdown of San Juan Unit 1 in June 2022.

The increase was partially offset by:

•$3 million in higher depreciation expense primarily due to an increase in asset base.

Performance - The first nine months of 2022 compared with the first nine months of 2021

TEP reported net income of $194 million in the first nine months of 2022 compared with net income of $183 million in the first nine months of 2021. The increase of $11 million, or 6%, was primarily due to:

•$16 million in higher margin from wholesale transactions primarily due to an increase in sales volume;

•$14 million in higher transmission revenue primarily due to the 2019 FERC Rate Order settlement agreement triggering recognition of revenue previously reserved for refund;

•$7 million in higher retail revenue primarily due to higher usage as a result of more favorable weather and increased LFCR revenue; and

The increase was partially offset by:

•$12 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions;

•$11 million in lower AFUDC due to a decrease in eligible construction expenditures primarily as a result of Oso Grande being placed in service in May 2021; and

•$11 million in higher depreciation expense due to an increase in asset base.

FACTORS AFFECTING RESULTS OF OPERATIONS

Several factors affect our current and future results of operations. The most significant factors are related to regulatory matters, generation resource strategy, and weather patterns.

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 2021 Annual Report on Form 10-K/A and new regulatory matters occurring in 2022.

2022 Rate Case

In June 2022, we filed a general rate case with the ACC based on a test year ended December 31, 2021.

Our key 2022 Rate Case proposals are described below:

•a $136 million net increase in retail revenues comprised of the following components:

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◦a non-fuel retail revenue increase of $159 million over test year non-fuel retail revenues;

◦a $66 million increase in fuel-related retail revenues, offset by a $71 million reduction in PPFAC revenues; and

◦changes in certain adjustor mechanisms, including DSM, ECA, and RES, that result in an $18 million reduction in revenues to be collected from customers.

•a 7.31% return on original cost rate base of $3.6 billion, which includes a cost of equity of 10.25% and an average cost of debt of 3.82%;

•a capital structure for rate making purposes of approximately 54% common equity and 46% long-term debt; and

•a new Resource Transition Mechanism adjustor that is designed to provide more timely recovery of our clean energy investments and replace the ECA.

We requested new rates to be implemented by September 1, 2023. We cannot predict the timing or outcome of this proceeding.

2020 ACC Phase 2 Proceedings

In 2020, the ACC issued a rate order for new rates and established a second phase of our rate case to address the impact on certain communities due to the closures of fossil fuel-based generation facilities (Phase 2). In 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. In January 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. In September 2022, the ACC issued a proposed order in the generic docket that would require us to file economic impact studies with the ACC prior to the closure of fossil fuel-based generation facilities. We cannot predict the timing or outcome of these proceedings.

Energy Imbalance Market

In 2019, we signed an agreement with the California Independent System Operator indicating our intent to begin participating in the Energy Imbalance Market (EIM) that we subsequently entered in May 2022. The EIM is a real-time energy market intended to find automatically low-cost energy to serve real-time consumer demand across a wide geographic area. Participation in the EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the EIM, we must demonstrate resource adequacy through a combination of owned or contracted resources. Our participation in the EIM is expected to: (i) reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance reliability through improved system utilization and responsiveness.

2019 FERC Rate Order

In 2019, we filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more timely recovery of transmission-related costs. The FERC issued an order approving our proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the 2019 FERC Rate Order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.

Provisions of the settlement agreement include, but are not limited to:

•replacing our stated transmission rates with a single forward-looking formula rate;

•a 9.79% 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.

Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. As of July 2022, we had returned all amounts in excess of the rates approved in the settlement agreement previously deferred as a regulatory liability. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q

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for additional information.

Other FERC Matters

In January 2021, the FERC notified us that it was commencing an audit with the intent 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 covers the period of January 1, 2018, to December 31, 2021. In September 2022, we received a draft audit report and responded to the recommendations and findings in the report on October 17, 2022. We are awaiting the final audit report and do not expect a material financial impact from the report.

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 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.

In February 2022, the ACC acknowledged our 2020 IRP, and found it to be reasonable and in the public interest. Our 2020 IRP calls for us to reduce our carbon emissions by 80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In April 2022, we issued an All-Source Request for Proposals (ASRFP), which requests new wind and solar generation, energy storage systems, and other resources such as energy efficiency resources. As part of the ASRFP, we are seeking bids for all resource types, including:

•up to 250 MW of renewable and energy efficiency resources, including new wind and solar generation systems and new energy efficiency initiatives, including demand response programs that reduce usage during periods of high energy demand; and

•up to 300 MW of “firm capacity” resources that can be called on at any time, including energy storage systems designed to provide at least four hours of continuous energy every day during the summer for us to dispatch as needed.

Our existing coal-fired generation fleet faces a number of uncertainties affecting 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-fired generation facilities over the next decade. In June 2022, San Juan Unit 1 was retired, which decreased our coal-fired generating capacity by 170 MW. 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 in future rate proceedings. We filed the 2022 Rate Case with the ACC in June 2022.

Renewable Energy Projects

In 2021 and 2022, additional renewable energy projects were added to our resource portfolio increasing our total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 700 MW.

Oso Grande

Production Tax Credits

PTCs are per kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In May 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in earnings. We recorded approximately $11 million and $19 million in PTCs related to Oso Grande in the three and nine months ended September 30, 2022, respectively. The IRS published PTC rate for electricity produced by a qualified facility using wind is $0.026 for 2022 and was $0.025 for 2021.

Contractual Provisions

If actual availability of the Oso Grande wind turbines is below a contractually established availability factor, we are entitled to liquidated damages to partially offset incremental operations and maintenance costs incurred. We recorded a reduction related to Oso Grande liquidated damages in Operations and Maintenance on the Condensed Consolidated Statements of Income of $1 million and $2 million in the three and nine months ended September 30, 2022, respectively, and $1 million in the three and nine months ended September 30, 2021. Any liquidated damages in excess of incremental operations and maintenance expenses

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will reduce Utility Plant—Plant in Service on the Condensed Consolidated Balance Sheets. The PTCs and liquidated damages will mostly offset the operating expenses of Oso Grande, which is 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.

Arizona Energy Policy

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various clean 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, but such rules have not been officially proposed. In 2021, a company filed an application with the ACC requesting a certificate of public convenience and necessity that would grant it the authority to provide competitive electric generation service to customers in our service territory. In April 2022, the Governor of Arizona signed legislation that repealed statutes supporting statewide implementation of retail electric competition. The ACC has not yet determined whether to consider the application in light of this legislation.

In January 2022, the ACC voted to open a new rule-making docket on integrated resource planning. We cannot predict the timing or outcome of this proceeding.

Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first 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 2021 Annual Report on Form 10-K/A 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, RES 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.

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The following discussion provides the significant items that affected TEP's results of operations in the third quarter and first nine months of 2022 compared with the same periods in 2021 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:


	Three Months Ended September 30,				Increase (Decrease)		Nine Months Ended September 30,				Increase (Decrease)
(in millions)	2022		2021		Percent		2022		2021		Percent
Operating Revenues
Retail	$	376	$	355	5.9	%	$	900	$	867	3.8	%
Wholesale, Long-Term	30		19		57.9	%	72		39		84.6	%
Wholesale, Short-Term (1)	114		82		39.0	%	223		173		28.9	%
Transmission	17		7		142.9	%	44		27		63.0	%
Springerville Units 3 and 4 Participant Billings	26		20		30.0	%	65		71		(8.5)	%
Other	24		25		(4.0)	%	60		59		1.7	%
Total Operating Revenues	$	587	$	508	15.6	%	$	1,364	$	1,236	10.4	%

(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, other than those specifically associated with long-term contracts, are included in Wholesale, Short-Term in the table above.

TEP reported Operating Revenues of $587 million in the third quarter of 2022 compared with $508 million in the same period for 2021. The increase of $79 million, or 16%, was primarily due to:

•$38 million in higher short-term wholesale sales primarily due to an increase in price; partially offset by a decrease in volume;

•$26 million in higher retail revenue primarily due to higher PPFAC cost recoveries as a result of a higher PPFAC rate and higher sales due to favorable weather;

•$11 million in higher long-term wholesale sales primarily due to an increase in volume;

•$9 million in higher transmission revenue due to an increase in volume and the 2019 FERC Rate Order settlement agreement triggering recognition of revenue previously reserved for refund; and

•$3 million in higher participant billings related to reimbursable maintenance expense for Springerville Unit 3.

The increase was partially offset by $5 million in lower margin from wholesale transactions.

TEP reported Operating Revenues of $1,364 million in the first nine months of 2022 compared with $1,236 million in the same period for 2021. The increase of $128 million, or 10%, was primarily due to:

•$47 million in higher short-term wholesale sales primarily due to an increase in price; partially offset by a decrease in volume;

•$38 million in higher retail revenue primarily due to higher PPFAC cost recoveries as a result of a higher PPFAC rate and higher usage due to favorable weather;

•$33 million in higher long-term wholesale sales primarily due to an increase in volume; and

•$16 million in higher transmission revenue due to an increase in volume and the 2019 FERC Rate Order settlement agreement triggering recognition of revenue previously reserved for refund;

The increase was partially offset by $9 million in lower participant billings related to Springerville Units 3 and 4 planned generation outages in 2021, not recurring in 2022.

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The following table provides key statistics impacting Operating Revenues:


	Three Months Ended September 30,		Increase (Decrease)		Nine Months Ended September 30,		Increase (Decrease)
(kWh in millions)	2022	2021	Percent		2022	2021	Percent
Electric Sales (kWh) (1)
Retail Sales	2,828	2,778	1.8	%	6,940	6,886	0.8	%
Wholesale, Long-Term (2)	451	280	61.1	%	1,176	591	99.0	%
Wholesale, Short-Term	1,182	1,363	(13.3)	%	3,386	4,135	(18.1)	%
Total Electric Sales	4,461	4,421	0.9	%	11,502	11,612	(0.9)	%

Average Revenue per kWh (3)
Retail	13.30	12.77	4.2	%	12.97	12.59	3.0	%
Wholesale, Long-Term	6.60	6.87	(3.9)	%	6.14	6.60	(7.0)	%
Wholesale, Short-Term	9.63	5.79	66.3	%	6.32	4.09	54.5	%

Total Retail Customers (4)					442,104	437,632	1.0	%

(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 long-term wholesale 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 $259 million in the third quarter of 2022 compared with $204 million in the same period for 2021. The increase of $55 million, or 27%, was primarily due to:

•$26 million in higher fuel costs primarily due to an increase in natural gas prices; partially offset by higher realized gains on natural gas swaps;

•$20 million decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; and

•$7 million in higher transmission costs due to an increase in transmission purchases.

TEP reported Fuel and Purchased Power expense of $555 million in the first nine months of 2022 compared with $462 million in the same period for 2021. The increase of $93 million, or 20%, was primarily due to:

•$43 million in higher fuel costs primarily due to an increase in natural gas prices; partially offset by a decrease in Gas-Fired Generation volumes;

•$30 million decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; and

•$15 million in higher transmission costs due to an increase in transmission purchases.

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The following table provides key statistics impacting Fuel and Purchased Power:


	Three Months Ended September 30,		Increase (Decrease)		Nine Months Ended September 30,		Increase (Decrease)
(kWh in millions)	2022	2021	Percent		2022	2021	Percent
Sources of Energy
Coal-Fired Generation	1,072	1,338	(19.9)	%	3,718	3,794	(2.0)	%
Gas-Fired Generation	1,987	2,138	(7.1)	%	4,791	5,713	(16.1)	%
Utility-Owned Renewable Generation (1)	168	93	80.6	%	645	450	43.3	%
Total Generation	3,227	3,569	(9.6)	%	9,154	9,957	(8.1)	%
Purchased Power, Non-Renewable	1,161	859	35.2	%	1,901	1,452	30.9	%
Purchased Power, Renewable (2)	270	229	17.9	%	1,016	721	40.9	%
Total Generation and Purchased Power (3)	4,658	4,657	—	%	12,071	12,130	(0.5)	%


(cents per kWh)
Average Fuel Cost of Generated Power (4)
Coal	3.04	2.61	16.5	%	2.71	2.52	7.5	%
Natural Gas (5)	4.83	3.98	21.4	%	4.41	3.40	29.7	%
Average Cost of Purchased Power (6)
Purchased Power, Non-Renewable	7.73	8.28	(6.6)	%	7.20	8.00	(10.0)	%
Purchased Power, Renewable	7.03	7.31	(3.8)	%	6.79	7.74	(12.3)	%

(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 solar facility achieved commercial operation, adding 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 analyze the performance of generation stations.

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

(6)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.

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Operations and Maintenance Expense

TEP reported Operations and Maintenance expense of $98 million in the third quarter of 2022 compared with $95 million in the same period for 2021. The increase of $3 million, or 3%, was primarily due to:

•$5 million in higher reimbursable maintenance expense related to Springerville Units 3 and 4; and

•$4 million in higher generation operations and outside service expenses.

The increase was partially offset by $6 million in lower operations expense related to the retirement of San Juan Unit 1 in June 2022.

TEP reported Operations and Maintenance expense of $296 million in the first nine months of 2022 compared with $301 million in the same period for 2021. The decrease of $5 million, or 2%, was primarily due to:

•$6 million in lower reimbursable maintenance expense related to Springerville Unit 4 planned outages in 2021, not recurring in 2022;

•$5 million in lower maintenance expense related to planned outages in 2021, not recurring in 2022; and

•$5 million in lower operations expense related to the retirement of San Juan Unit 1 in June 2022.

The decrease was partially offset by $10 million in higher generation operations and outside service expenses.

Depreciation and Amortization Expense

TEP reported Depreciation and Amortization expense of $65 million in the third quarter of 2022 compared with $63 million in the same period for 2021. The increase of $2 million, or 3%, was primarily due to an increase in asset base.

TEP reported Depreciation and Amortization expense of $193 million in the first nine months of 2022 compared with $181 million in the same period for 2021. The increase of $12 million, or 7%, was primarily due to an increase in asset base.

Other Income (Expense)

TEP reported other expense of $16 million in the third quarter of 2022 compared with $18 million in the same period for 2021. The decrease of $2 million, or 11%, was primarily due to $2 million in lower interest expense related to the redemption of senior notes in August 2021 and tax-exempt bonds in March and June 2022.

TEP reported other expense of $53 million in the first nine months of 2022 compared with $36 million in the same period for 2021. The increase of $17 million, or 47%, was primarily due to:

•$12 million in lower AFUDC primarily due to a decrease in eligible construction expenditures as a result of Oso Grande being placed in service in May 2021; and

•$11 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions.

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Income Tax Expense

TEP reported Income Tax Expense of $14 million in the third quarter of 2022 compared with $17 million in the same period for 2021. The decrease of $3 million, or 18%, was primarily due to a $9 million increase in PTCs as a result of Oso Grande being placed in service in May 2021. The decrease was partially offset by $5 million in higher tax expense due to an increase in taxable earnings.

TEP reported Income Tax Expense of $24 million in the first nine months of 2022 compared with $27 million in the same period for 2021. The decrease of $3 million, or 11%, was primarily due to an $11 million increase in PTCs as a result of Oso Grande being placed in service in May 2021.

The decrease was partially offset by:

•$3 million in higher tax expense due to a non-tax deductible decrease in the value of investments used to support certain post-employment benefits;

•$2 million due to lower AFUDC equity due to a decrease in eligible construction expenditures; and

•$2 million in higher tax expense due to an increase in taxable earnings.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Any extended period of economic disruption could affect our business and financial conditions, and access to sources of liquidity. Cash flows 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 as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 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)	September 30, 2022
Cash and Cash Equivalents	$	153
Amount Available under Revolving Credit Agreement (1)	240
Total Liquidity	$	393

(1)The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026. See Access to Credit Agreement below.

Future Liquidity Requirements

We expect to meet all of our short and long-term 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) known commitments and other obligations including forecasted capital expenditures.

See Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk of this Form 10-Q for additional information regarding TEP's market risks and Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item I of this Form 10-Q for additional information regarding TEP's financing arrangements.

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Summary of Cash Flows

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


	Nine Months Ended September 30,				Increase (Decrease)
(in millions)	2022		2021		Percent
Operating Activities	$	438	$	343	27.7	%
Investing Activities	(337)		(398)		(15.3)	%
Financing Activities	43		83		(48.2)	%
Net Increase	144		28		414.3	%
Beginning of Period	33		82		(59.8)	%
End of Period (1)	$	177	$	110	60.9	%

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

Operating Activities

In the first nine months of 2022, net cash flows from operating activities increased by $95 million compared with the same period in 2021. The increase was primarily due to: (i) changes in working capital related to the timing of billing collections and cash collateral deposits received from counterparties due to high natural gas forward prices; and (ii) higher margin from wholesale transactions and an increase in transmission volumes and rates; (iii) higher retail revenue primarily due to higher PPFAC cost recoveries as a result of a higher PPFAC rate and higher sales due to favorable weather; and (iv) lower operations and maintenance expenses due to the shutdown of San Juan Unit 1 in June 2022.

Investing Activities

In the first nine months of 2022, net cash flows used for investing activities decreased by $61 million compared with the same period in 2021 primarily due to a decrease in cash paid for capital expenditures in 2022.

Financing Activities

In the first nine months of 2022, net cash flows from financing activities decreased by $40 million compared with the same period in 2021 primarily due to: (i) lower proceeds from credit facility borrowings, net of repayments; (ii) an increase in dividends declared and paid to UNS Energy; and (iii) a decrease in equity contributions from UNS Energy.

Sources of Liquidity

Short-Term Investments

Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of September 30, 2022, TEP's short-term investments included highly-rated and liquid money market funds and insured cash sweep accounts.

Access to Credit Agreement

We have access to working capital through our credit agreement with lenders.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2021 Annual Report on Form 10-K/A for additional information regarding our 2021 Credit Agreement.

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 December 2020, the ACC issued an order granting TEP financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate.

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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 February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032 with proceeds used to redeem debt and for general corporate purposes.

•In March 2022, TEP redeemed at par prior to maturity $177 million in aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.

•In June 2022, TEP redeemed at par prior to maturity $16 million in aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2022, 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.

The 2021 Credit Agreement contains pricing based on our credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.

Debt Covenants

Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2022, TEP was in compliance with these covenants.

We do not have any provisions in any of our debt 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 no equity contributions from UNS Energy in the third quarter or first nine months of 2022. TEP received no equity contributions in the third quarter of 2021 and received an equity contribution of $50 million in the first nine months of 2021.

Dividends Declared and Paid to Parent

TEP declared and paid $75 million in dividends to UNS Energy in the third quarter and first nine months of 2022. TEP declared and paid a $38 million dividend to UNS Energy in the third quarter and first nine months of 2021.

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 established for TEP based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of September 30, 2022, TEP had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.

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Capital Expenditures

TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. TEP is prioritizing capital projects to mitigate supply chain risk particularly in view of heightened geopolitical instability and global supply chain challenges. Capital expenditures for the first nine months of 2022 were $296 million.

Our forecasted capital expenditures presented below exclude amounts for AFUDC equity and other non-cash items:


	Years Ended December 31,
(in millions)	2022		2023		2024		2025		2026
Generation Facilities:
Renewable Energy (1)	$	71	$	235	$	41	$	136	$	298
Other Generation Facilities	86		68		45		89		70
Total Generation Facilities	157		303		86		225		368
Transmission and Distribution (2)	268		293		289		312		276
General and Other (3)	89		85		69		80		71
Total Capital Expenditures	$	514	$	681	$	444	$	617	$	715

(1)Includes investments in renewable energy and battery energy storage systems, which we expect will allow us to continue our long-term strategy of transitioning to a more sustainable energy portfolio.

(2)Increases due to investments in transmission capacity and distribution system reliability.

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

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

Income Tax Position

Under the terms of the tax sharing agreement with UNS Energy, TEP made $2 million in tax sharing payments in the first nine months of 2022 and made $4 million in tax sharing payments in the first nine months of 2021. We do not anticipate making additional tax payments for the remainder of 2022. Future payment obligations are subject to change and are not expected to have a significant impact on our operating cash flows.

Inflation Reduction Act

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (IRA) into law. The IRA did not result in any immediate financial statement impacts for the Company. However, the legislation does contain a new corporate alternative minimum tax (AMT) of 15% that will apply to certain corporations provided a specified set of conditions are met. We are currently evaluating whether the AMT will apply to TEP based on the foreign-parent company rules as well as pending interpretive guidance. The AMT will be effective for tax years beginning after December 31, 2022.

Wage Expenses

Payroll Tax Deferred Payments

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 Condensed Consolidated Balance Sheets. The aggregate liability balance related to the CARES Act was $2 million as of September 30, 2022, and $4 million as of December 31, 2021. TEP expects to pay the remaining deferred deposits to the IRS by the end of 2022.

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Collective Bargaining Agreements

The current collective bargaining agreement between the International Brotherhood of Electrical Workers Local No. 1116 (IBEW) and TEP expired July 31, 2022, with wages in effect through December 2022. IBEW and TEP extended the bargaining agreement through June 30, 2023, including a wage increase. Full negotiations are ongoing.

Environmental Matters

The Environmental Protection Agency (EPA) has the authority to regulate 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 ADEQ submitted the revised SIP to the EPA in August 2022. The EPA issued a letter to the ADEQ finding Arizona's SIP revision complies with the completeness criteria outlined in the rule. By statute, the EPA has one year from the completeness determination to take action on Arizona's SIP revision. Based on current Regional Haze requirement time-frames, TEP anticipates that compliance strategies, if any, will likely be required to be implemented two years after the ADEQ's submission of 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.

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 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.

In 2021, the U.S. Court of Appeals for the D.C. Circuit: (i) vacated the EPA's repeal of the CPP and remanded it back to the EPA for further consideration (the vacatur was later stayed by the court); and (ii) vacated and remanded the ACE rule. Certain petitioners, defending the repeal of the CPP, filed petitions for an order requesting that the U.S. Supreme Court review the decision of the lower court. The U.S. Supreme Court granted the petitions, consolidated the cases, and issued an opinion in June 2022 concerning the scope of the EPA's authority to regulate GHG emissions from existing coal-fired generation facilities under the Clean Air Act in June 2022. The U.S. Supreme Court reversed the D.C. Circuit and remanded the cases back for further proceedings consistent with the June 2022 opinion.

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 completed the assessment in 2022. The proposed final remedy was presented to the public in August 2022, and a final remedy report is being prepared.

Since these regulations were finalized, the EPA has taken steps to further modify the 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 the WIIN 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.

•In March 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.

As of September 30, 2022, the EPA has not taken final action on these proposals. As a result, TEP cannot predict the outcome or timing 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. With the exception of Four Corners, none of TEP's coal-fired generation facilities are subject to the rule.

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 and warrants a modification of Four Corners' National Pollution Discharge Elimination System permit. APS, the operator of Four Corners, filed a permit modification request in January 2021. APS has been working with the EPA on an Initial Certification Statement, which is still in draft format and pending EPA final action. TEP cannot predict the timing or final outcome of these matters at this time.

National Pollution Discharge Elimination System Permit

Several environmental non-governmental organizations (Petitioners) sought review of the EPA’s September 2019 issuance of Four Corners’ current National Pollution Discharge Elimination System permit from the EPA Environmental Appeals Board (EAB) in November 2019. The EAB denied the petition in September 2020. In May 2022, the Petitioners, APS, and the EPA executed a settlement agreement. The EPA has procured a contractor to conduct the surface water sampling program as outlined in the settlement agreement and is finalizing the scope of the work for the sampling program. TEP cannot predict the timing or outcome of the proceeding, but we do not expect this matter to have a material impact on our financial statements.

CRITICAL ACCOUNTING 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 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 nine months ended September 30, 2022, to the items that we disclosed as our critical accounting estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2021 Annual Report on Form 10-K/A.

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NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We can enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows but are not expected to affect earnings due to expected recovery through regulatory mechanisms.

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2021 Annual Report on Form 10-K/A.

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 September 30, 2022. There was no change in TEP’s internal control over financial reporting during the quarter ended September 30, 2022, 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 2021 Annual Report on Form 10-K/A should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2021 Annual Report on Form 10-K/A.

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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 September 30, 2022, 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:	October 27, 2022	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President, Chief Financial Officer, and Director
		(Principal Financial Officer)