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, 2023

OR

☐    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 26, 2023.

Table of Contents

Definitions	iii
Forward-Looking Information	iv
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	19
Critical Accounting Estimates	31
New Accounting Standards Issued and Not Yet Adopted	31
Item 3. Quantitative and Qualitative Disclosures about Market Risk	31
Item 4. Controls and Procedures	31
PART II
Item 1. Legal Proceedings	32
Item 1A. Risk Factors	32
Item 6. Exhibits	33
Signatures	34

ii

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

2022 Final FERC Rate Order	Order issued by the FERC in 2022 approving the settlement agreement filed in conjunction with TEP's 2019 transmission rate case
2020 IRP	TEP's 2020 Integrated Resource Plan, which calls for TEP to reduce its carbon emissions by 80% by 2035
2021 Credit Agreement	The 2021 Credit Agreement, as amended in June 2023, 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
2023 Rate Order	Order issued by the ACC resulting in a new rate structure for TEP, effective on September 1, 2023
ABR	Alternate Base Rate
ACC	Arizona Corporation Commission
ADJ	SOFR Rate Spread Adjustment
AFUDC	Allowance for Funds Used During Construction
BESS	Battery Energy Storage System
DG	Distributed Generation
DSM	Demand Side Management
EIM	Energy Imbalance Market
EPC	Engineering, Procurement, and Construction
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
IRA	Inflation Reduction Act, signed into law on August 16, 2022
LFCR	Lost Fixed Cost Recovery
LOC	Letter(s) of Credit
OATT	Open Access Transmission Tariff
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
PTC	Production Tax Credit
RES	Renewable Energy Standard
Retail Rates	Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
SOFR	Secured Overnight Financing Rate

ENTITIES AND GENERATING STATIONS

Fortis	Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners	Four Corners Generating Station
Oso Grande	A 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
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy
UNS Electric	UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy
UNS Energy	UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates	Affiliated subsidiaries of UNS Energy including UniSource Energy Services, Inc., UNS Electric, and UNS Gas
UNS Gas	UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy

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
MWh	Megawatt-hour(s), a measure of electricity that represents one million watts of power expended over one hour

iii

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 2022 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Form 10-Q; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax, inclusive of the IRA and evolving interpretive guidance related thereto, and energy policies; 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; 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; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; potential changes in the benefits of participation in the EIM; 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 our operational performance; 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 to 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; our ability to manage timelines and budgets related to capital projects, including the EPC agreement to develop a standalone BESS facility, and/or to obtain the anticipated performance or other benefits of such capital projects; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense, including increases due to inflationary effects, heightened geopolitical instability, and/or global supply chain challenges; 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; our ability to effectively implement plans to meet our goals related to reducing carbon emissions by 2035, and the potential impact on our financial condition; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas 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; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; the extent of the impact of a global health or other crises on our business and operations, and any economic and/or societal disruptions resulting therefrom and from the government actions taken in response thereto; and the expected timing and contents of the upcoming 2023 Integrated Resource Plan.

iv

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,
	2023		2022		2023		2022
Operating Revenues	$	593,247	$	587,262	$	1,447,336	$	1,363,515
Operating Expenses
Fuel	107,917		147,246		296,617		336,020
Purchased Power	98,081		89,709		181,657		173,740
Transmission and Other PPFAC Recoverable Costs	29,517		26,566		61,478		64,312
Increase (Decrease) to Reflect PPFAC Recovery Treatment	7,659		(4,924)		42,156		(19,170)
Total Fuel and Purchased Power	243,174		258,597		581,908		554,902
Operations and Maintenance	103,991		97,874		332,033		296,444
Depreciation	49,901		55,039		144,465		163,087
Amortization	9,487		10,294		28,981		30,151
Taxes Other Than Income Taxes	17,068		15,966		51,448		47,930
Total Operating Expenses	423,621		437,770		1,138,835		1,092,514
Operating Income	169,626		149,492		308,501		271,001
Other Income (Expense)
Interest Expense	(23,986)		(21,304)		(71,474)		(63,938)
Allowance For Borrowed Funds	1,279		614		3,448		2,026
Allowance For Equity Funds	3,637		1,874		9,779		5,915
Unrealized Gains (Losses) on Investments	(1,331)		(1,794)		462		(8,515)
Other, Net	2,463		4,611		8,220		11,033
Total Other Income (Expense)	(17,938)		(15,999)		(49,565)		(53,479)
Income Before Income Tax Expense	151,688		133,493		258,936		217,522
Income Tax Expense	23,357		14,196		35,986		23,831
Net Income	$	128,331	$	119,297	$	222,950	$	193,691

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

1

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)

	Nine Months Ended September 30,
	2023		2022
Cash Flows from Operating Activities
Net Income	$	222,950	$	193,691
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	144,465		163,087
Amortization Expense	28,981		30,151
Amortization of Debt Issuance Costs	2,304		2,241
Use of Renewable Energy Credits for Compliance	33,770		34,380
Deferred Income Taxes	28,649		23,853
Pension and Other Postretirement Benefits Expense	11,398		8,735
Pension and Other Postretirement Benefits Funding	(11,499)		(15,701)
Allowance for Equity Funds Used During Construction	(9,779)		(5,915)
Change in Long-Term Regulatory Assets and Liabilities	257		45,005
Changes in Current Assets and Current Liabilities:
Accounts Receivable	43,869		(160,267)
Materials, Supplies, and Fuel Inventory	(21,826)		6,097
Regulatory Assets	32,204		(54,019)
Other Current Assets	(6,112)		(3,926)
Accounts Payable and Accrued Charges	(62,182)		168,928
Income Taxes Receivable/Payable	1,315		(1,490)
Regulatory Liabilities	(12)		1,184
Other, Net	(10,415)		1,736
Net Cash Flows—Operating Activities	428,337		437,770
Cash Flows from Investing Activities
Capital Expenditures	(345,470)		(296,014)
Purchase Intangibles, Renewable Energy Credits	(48,915)		(49,728)
Other Investments	2,935		2,517
Contributions in Aid of Construction	3,355		6,495
Net Cash Flows—Investing Activities	(388,095)		(336,730)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	—		5,000
Repayments of Borrowings, Revolving Credit Facility	—		(20,000)
Proceeds from Issuance, Long-Term Debt—Net of Discount	373,954		323,804
Repayments of Long-Term Debt	(240,745)		(193,465)
Dividend Paid to Parent	(55,000)		(75,000)
Payment of Debt Issuance Costs	(4,095)		(3,010)
Contribution from Parent	5,900		—
Other, Net	(383)		5,467
Net Cash Flows—Financing Activities	79,631		42,796
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	119,873		143,836
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	50,981		33,489
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	170,854	$	177,325

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

2

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	September 30, 2023		December 31, 2022
ASSETS
Utility Plant
Plant in Service	$	7,946,703	$	7,813,680
Construction Work in Progress	389,150		256,044
Total Utility Plant	8,335,853		8,069,724
Accumulated Depreciation and Amortization	(2,570,080)		(2,603,730)
Total Utility Plant, Net	5,765,773		5,465,994
Investments and Other Property	63,003		74,128
Current Assets
Cash and Cash Equivalents	137,585		16,237
Accounts Receivable (Net of Allowance for Credit Losses of $11,458 and $9,012)	270,137		320,899
Fuel Inventory	38,602		28,681
Materials and Supplies	167,555		155,650
Regulatory Assets	157,406		185,034
Derivative Instruments	11,578		27,019
Other	36,456		30,547
Total Current Assets	819,319		764,067
Regulatory and Other Assets
Regulatory Assets	171,418		184,894
Derivative Instruments	41,403		77,123
Other	146,327		123,575
Total Regulatory and Other Assets	359,148		385,592
Total Assets	$	7,007,243	$	6,689,781

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

(Continued)

3

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	September 30, 2023		December 31, 2022
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, 2023 and December 31, 2022)	$	1,702,439	$	1,696,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	1,136,317		968,367
Accumulated Other Comprehensive Loss	(2,801)		(2,884)
Total Common Stock Equity	2,829,598		2,655,665
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2023 and December 31, 2022)	—		—
Long-Term Debt, Net	2,396,038		2,114,980
Total Capitalization	5,225,636		4,770,645
Current Liabilities
Current Maturities of Long-Term Debt, Net	—		149,957
Accounts Payable	151,565		233,920
Accrued Taxes Other Than Income Taxes	81,424		58,914
Accrued Employee Expenses	37,551		38,459
Accrued Interest	32,145		14,868
Regulatory Liabilities	100,668		110,782
Customer Deposits	15,857		14,073
Derivative Instruments	9,756		12,752
Other	39,269		49,163
Total Current Liabilities	468,235		682,888
Regulatory and Other Liabilities
Deferred Income Taxes, Net	634,394		590,926
Regulatory Liabilities	421,146		377,546
Pension and Other Postretirement Benefits	69,724		69,048
Derivative Instruments	1,738		4,787
Other	186,370		193,941
Total Regulatory and Other Liabilities	1,313,372		1,236,248
Commitments and Contingencies
Total Capitalization and Other Liabilities	$	7,007,243	$	6,689,781

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

(Concluded)

4

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, 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
Dividend 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

Balances as of June 30, 2023	$	1,702,439	$	(6,357)	$	1,007,986	$	(2,829)	$	2,701,239
Net Income					128,331				128,331
Other Comprehensive Income, Net of Tax							28		28
Balances as of September 30, 2023	$	1,702,439	$	(6,357)	$	1,136,317	$	(2,801)	$	2,829,598

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

Balances as of December 31, 2022	$	1,696,539	$	(6,357)	$	968,367	$	(2,884)	$	2,655,665
Net Income					222,950				222,950
Other Comprehensive Income, Net of Tax							83		83
Dividend Declared to Parent					(55,000)				(55,000)
Contribution from Parent	5,900								5,900
Balances as of September 30, 2023	$	1,702,439	$	(6,357)	$	1,136,317	$	(2,801)	$	2,829,598

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

5

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 446,000 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 United States Securities and Exchange Commission's (SEC) interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems 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 2022 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no impact on TEP's results of operation, financial position, or cash flows.

Variable Interest Entities

A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a 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 the primary beneficiary of the VIEs on a quarterly basis.

As of September 30, 2023, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term renewable PPAs were 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.

6

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 Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows:

	Nine Months Ended September 30,
(in millions)	2023		2022
Cash and Cash Equivalents	$	138	$	153
Restricted Cash included in:
Investments and Other Property	20		21
Current Assets—Other	13		3
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	171	$	177

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

Income Tax Expense

TEP realized PTC benefits associated with Oso Grande of $7 million and $16 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2023, respectively, and $11 million and $19 million for the three and nine months ended September 30, 2022, respectively.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) was adopted and reflected in TEP's financial statements in the second quarter of 2023. Adoption of the new guidance had an insignificant impact on TEP's financial position, results of operations, cash flows, and disclosures.

Reference Rate Reform

In 2020, the FASB issued Accounting Standards Update (ASU) 2020-04 establishing Accounting Standards Codification (ASC) Topic 848, Reference Rate Reform, and in 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (collectively, ASC 848). ASC 848 contains practical expedients for reference rate reform-related activities that impact debt, leases, derivatives, and other contracts. The guidance in ASC 848 is optional and may be elected over time as reference rate reform activities occur. In 2022, the FASB issued ASU 2022-06, Deferral of the Sunset Date of Topic 848, to defer the sunset date of ASC 848 to December 31, 2024. ASU 2022-06 became effective immediately.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

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

NOTE 2. REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect TEP's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

RATE CASE MATTERS

2023 Rate Order

In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;

•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% 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;

•approval to recover costs of changes in generation resources, including the addition of Oso Grande in rates; and

•denial of a request for a System Reliability Benefit adjustor that was designed to provide more timely recovery of TEP's energy resource investments.

In January 2023, the ACC ordered that funding for the just and equitable transition away from fossil fuel-based economies for communities impacted by early coal-fired plant closures be considered as part of the 2023 Rate Order. In the 2023 Rate Order, the ACC determined that there was insufficient evidence to support customer funding for the just and equitable transition as part of the proceeding.

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 covered the period of January 1, 2018 to December 31, 2021. In November 2022, the FERC published its findings and recommendations. TEP accepted the findings therein and, in May 2023, issued refunds to customers of $1 million related to the audit. All compliance activities related to the audit were completed by the end of the second quarter of 2023, and a final status update was submitted to the FERC in July 2023.

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 set the true-up component of the PPFAC rate to recover the then existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which contributed to under-collection of PPFAC costs. In May 2023, the ACC approved a rate adjustment for the PPFAC to collect the remaining uncollected balance over 12 months.

In the 2023 Rate Order, the ACC approved a change to the PPFAC plan of administration to allow the recovery of costs incurred in purchasing carbon allowances to comply with regulations associated with the EIM.

8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2023		2022		2023		2022
Beginning of Period	$	93	$	103	$	124	$	91
Deferred Fuel and Purchased Power Costs (1)	135		116		258		269
PPFAC and Base Power Recoveries	(140)		(109)		(294)		(250)
End of Period	$	88	$	110	$	88	$	110

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

Transmission Cost Adjustor

The Transmission Cost Adjustor (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. TEP files new TCA rates with the ACC in December each year based on changes in the OATT formula rate. New TCA rates take effect in January of each year.

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 2023 is 13% of retail electric sales. Consistent with prior years, TEP expects to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. 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 Tariff.

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. In June 2023, the ACC approved an extension of the 2021 RES implementation plan through 2024.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards. The Energy Efficiency Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs of implementing 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 the 2023 Rate Order, the ACC approved a 2023 energy efficiency implementation plan with a three-year budget of $72 million, which is collected through the DSM surcharge. Additionally, if there are any remaining uncommitted excess DSM surcharge funds by December 31, 2023, the ACC directed TEP to file by January 31, 2024, a proposal to refund the over-collected balance on a one or two-month refund period for the ACC's consideration.

2020 IRP Energy Efficiency Target

In 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP will report its savings for these years in its first integrated resource plan following 2025 and in TEP's periodic energy efficiency filings.

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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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, 2023		December 31, 2022
Regulatory Assets
Under Recovered Purchased Energy Costs	1	$	88	$	124
Pension and Other Postretirement Benefits (Note 8)	Various	86		90
Early Generation Retirement Costs	Various	54		58
Lost Fixed Cost Recovery	1	32		25
Property Tax Deferrals (1)	1	30		29
Final Mine Reclamation and Retiree Healthcare Costs (2)	5	10		11
Income Taxes Recoverable through Future Rates (3)	Various	6		6
Unamortized Loss on Reacquired Debt	Various	5		5
Derivatives (Note 9)	6	5		3
Other Regulatory Assets	Various	12		19
Total Regulatory Assets		328		370
Less Current Portion	1	157		185
Total Non-Current Regulatory Assets		$	171	$	185

Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	230	$	244
Net Cost of Removal (4)	Various	138		43
Renewable Energy Standard	Various	77		73
Derivatives (Note 9)	6	40		86
Demand Side Management	1	15		16
Pension and Other Postretirement Benefits (Note 8)	Various	8		8
Transmission Balancing Accounts	1	7		9
Deferred Investment Tax Credits	Various	6		7
Other Regulatory Liabilities	Various	1		3
Total Regulatory Liabilities		522		489
Less Current Portion	1	101		111
Total Non-Current Regulatory Liabilities		$	421	$	378

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

(2)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.

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

(4)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. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Under Recovered Purchased Energy Costs, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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 most of its regulatory liability balances.

NOTE 3. REVENUE

DISAGGREGATION OF REVENUES

TEP earns most 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)	2023		2022		2023		2022
Retail	$	445	$	376	$	975	$	900
Wholesale (1)	101		150		291		305
Other Services	25		30		95		77
Revenues from Contracts with Customers	571		556		1,361		1,282
Alternative Revenues	7		7		28		20
Other	15		24		58		62
Total Operating Revenues	$	593	$	587	$	1,447	$	1,364

(1)In 2022, the FERC issued the 2022 Final FERC Rate Order approving TEP's proposed OATT revisions. Prior to July 2022, wholesale revenues excluded an estimate of revenues probable of refund.

NOTE 4. ACCOUNTS RECEIVABLE

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

(in millions)	September 30, 2023		December 31, 2022
Retail	$	133	$	87
Retail, Unbilled	75		46
Retail, Allowance for Credit Losses	(11)		(9)
Wholesale (1)	40		132
Due from Affiliates (Note 5)	19		26
Other	14		39
Accounts Receivable	$	270	$	321

(1)Includes $15 million as of September 30, 2023, and $52 million as of December 31, 2022, of receivables related to revenue from derivative instruments.

ALLOWANCE FOR CREDIT LOSSES

TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2023		2022		2023		2022
Beginning of Period	$	(9)	$	(8)	$	(9)	$	(10)
Credit Loss Expense	(4)		(2)		(6)		(3)
Write-offs	2		1		4		4
End of Period	$	(11)	$	(9)	$	(11)	$	(9)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 5. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and 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, 2023		December 31, 2022
Receivables from Related Parties
UNS Electric	$	16	$	22
UNS Gas	2		2
UNS Energy	1		2
Total Due from Related Parties	$	19	$	26
Payables to Related Parties
UNS Electric	$	1	$	5
UNS Energy	1		1
UNS Gas	—		1
Total Due to Related Parties	$	2	$	7

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)	2023		2022		2023		2022
Goods and Services Provided by TEP to Affiliates
Wholesale Revenues, UNS Electric (1)	$	22	$	24	$	35	$	34
Common Costs, UNS Energy Affiliates (2)	6		5		17		16
Transmission Revenues, UNS Electric (1)	2		1		6		4
Control Area Services, UNS Electric (3)	1		—		2		2
Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (4)	$	2	$	1	$	6	$	6
Corporate Services, UNS Energy Affiliates (5)	—		—		1		1
Purchased Power, UNS Electric (1)	—		1		1		1
Capacity Charges, UNS Gas (6)	—		—		1		—

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

(2)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.

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

(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 $2 million and $6 million for the three and nine months ended September 30, 2023, respectively, and $1 million and $5 million for the three and nine months ended September 30, 2022, 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.

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

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

DIVIDEND DECLARED TO PARENT

On October 26, 2023, TEP declared a dividend of up to $15 million to be paid to UNS Energy on or before December 31, 2023.

NOTE 6. DEBT AND CREDIT AGREEMENT

There have been no significant changes to TEP's debt or credit agreement from those reported in its 2022 Annual Report on Form 10-K, except as noted below.

DEBT

Issuance and Redemptions

In February 2023, TEP issued and sold $375 million aggregate principal amount of 5.50% senior unsecured notes due April 2053. TEP may redeem the notes prior to October 15, 2052, with a make-whole premium plus accrued interest. On or after October 15, 2052, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem and repay debt and for general corporate purposes.

In March 2023, TEP repaid at maturity $150 million aggregate principal amount of 3.85% senior unsecured notes.

In March 2023, TEP redeemed at par prior to maturity $91 million aggregate principal amount of tax-exempt bonds bearing interest at a rate of 4.00% per annum.

CREDIT AGREEMENT

2021 Credit Agreement

In June 2023, the 2021 Credit Agreement was amended to provide for the transition to SOFR-based borrowings. Terms are as follows:

			Sub-Limit Swingline		Sub-Limit LOC						Weighted Average Interest Rate
	Capacity						Borrowed(1)		Available				Pricing
($ in millions)	September 30, 2023
Agreement	$	250	$	15	$	50	$	—	$	250	—	%	SOFR+ADJ 0.10%+1.025% or ABR+0.025%

(1)A $5 million LOC outstanding as of December 31, 2022, was cancelled in August 2023.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2022 Annual Report on Form 10-K, except as noted below.

EPC Agreement

In September 2023, TEP entered into an EPC agreement to develop a standalone BESS facility at a cost of $294 million. TEP will own and operate the facility, which will be located in southeast Tucson and have a nominal capacity rating of 200 MW and storage capacity of 800 MWh. The BESS facility is expected to be placed in service in the second half of 2025. As of October 26, 2023, TEP has made payments of $89 million in connection with the construction and development of the BESS facility.

Fuel, Including Transportation

TEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. In the first quarter of 2023, TEP amended and extended an agreement for gas transportation to Sundt through 2048. TEP's minimum purchase commitment is $5 million in each of 2023 through 2027 and $92 million thereafter.

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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 costs are subject to various assumptions, such as: (i) estimations of reclamation costs; (ii) timing of when final reclamation will occur; and (iii) 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 pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s share of final mine reclamation costs at Four Corners is $6 million upon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the coal supply agreement in June 2022. As of September 30, 2023, TEP’s remaining final mine reclamation liability at San Juan was $27 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 occur by 2039. See Note 1 for additional information on restricted cash.

TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation totaled $32 million and $37 million as of September 30, 2023, and December 31, 2022, respectively, and was recorded in Other on the Condensed Consolidated Balance Sheets.

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. There is no cap on the potential amount of future payments TEP could be required to make under the Luna guarantee. The aggregate maximum potential amount of future payments to the non-defaulting parties is $250 million at Four Corners. As of September 30, 2023, there have been no such payment defaults under either of the participation agreements.

The Navajo Generating Station (Navajo) and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, the non-defaulting participants would seek financial recovery directly from the defaulting party.

Environmental Matters

TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, water use, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:

	Pension Benefits				Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2023		2022		2023		2022
Service Cost	$	3	$	6	$	1	$	1
Non-Service Cost (1)
Interest Cost	6		4		1		—
Expected Return on Plan Assets	(8)		(9)		—		—
Amortization of Net Loss	1		1		—		—
Net Periodic Benefit Cost	$	2	$	2	$	2	$	1

	Nine Months Ended September 30,
(in millions)	2023		2022		2023		2022
Service Cost	$	9	$	16	$	3	$	4
Non-Service Cost (1)
Interest Cost	17		12		3		1
Expected Return on Plan Assets	(22)		(28)		(1)		(1)
Amortization of Net Loss	3		5		—		—
Net Periodic Benefit Cost	$	7	$	5	$	5	$	4

(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.

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, 2023
Assets
Cash Equivalents (1)	$	60	$	—	$	60
Restricted Cash (1)	34		—		34
Energy Derivative Contracts, Regulatory Recovery (2)	—		47		47
Energy Derivative Contracts, No Regulatory Recovery (2)	—		6		6
Total Assets	94		53		147
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(11)		(11)
Total Liabilities	—		(11)		(11)
Total Assets (Liabilities), Net	$	94	$	42	$	136

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

(in millions)	December 31, 2022
Assets
Restricted Cash (1)	$	35	$	—	$	35
Energy Derivative Contracts, Regulatory Recovery (2)	—		100		100
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	35		104		139
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(18)		(18)
Total Liabilities	—		(18)		(18)
Total Assets (Liabilities), Net	$	35	$	86	$	121

(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.

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

	Gross Amount Recognized in the Balance Sheets		Gross Amount Not Offset in the Balance Sheets				Net Amount
			Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted
(in millions)	September 30, 2023
Derivative Assets
Energy Derivative Contracts	$	53	$	9	$	—	$	44
Derivative Liabilities
Energy Derivative Contracts	(11)		(9)		—		(2)

(in millions)	December 31, 2022
Derivative Assets
Energy Derivative Contracts	$	104	$	14	$	14	$	76
Derivative Liabilities
Energy Derivative Contracts	(18)		(14)		—		(4)

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.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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

Energy Derivative Contracts, Regulatory Recovery

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2023		2022		2023		2022
Unrealized Net Gain (Loss) (1)	$	—	$	(1)	$	(47)	$	106

(1)For the nine months ended September 30, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas. For the nine months ended September 30, 2022, unrealized net gain on regulatory recoverable derivative contracts was 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 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)	2023		2022		2023		2022
Operating Revenues	$	1	$	—	$	18	$	10

Derivative Volumes

As of September 30, 2023, 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, 2023	December 31, 2022
Power Contracts GWh	2,729	1,979
Gas Contracts BBtu	88,780	96,755

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. If 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)    

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 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 $22 million as of September 30, 2023, compared with $86 million as of December 31, 2022. As of September 30, 2023, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on September 30, 2023, TEP would have been required to post $22 million of collateral. As of September 30, 2023, TEP had $21 million in outstanding net payable balances for settled positions.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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

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

	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,396	$	2,265	$	1,933	$	1,901

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)	2023		2022
Net Cost of Removal Increase (Decrease) (1)	$	98	$	(49)
Accrued Capital Expenditures	32		25
Renewable Energy Credits	4		4
Asset Retirement Obligation/Cost Increase (Decrease) (2)	(2)		(28)

(1)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. 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. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.

(2)TEP retired the San Juan asset retirement cost asset, concurrent with the retirement of San Juan Unit 1 in June 2022.

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

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

•outlook and strategies;

•factors affecting results of operations;

•results of operations;

•liquidity and capital resources, including capital expenditures, income tax position, and environmental matters;

•critical accounting estimates; and

•new accounting standards issued and adopted or 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 condensed consolidated 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 Form 10-Q and Risk Factors in Part 1, Item 1A of our 2022 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.

References in Management's Discussion and Analysis to "we" and "our" are to TEP.

OUTLOOK AND STRATEGIES

Our 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, regulations, and policies; 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% by 2035. In 2022, Fortis set a goal to achieve net-zero direct GHG 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.

Performance - The third quarter of 2023 compared with the third quarter of 2022

We reported net income of $128 million in the third quarter of 2023 compared with net income of $119 million in the third quarter of 2022. The increase of $9 million, or 8%, was primarily due to:

•$26 million in higher retail revenue primarily due to higher usage as a result of favorable weather and an increase in rates as approved in the 2023 Rate Order; and

•$5 million in lower depreciation expense primarily due to the retirement of San Juan Unit 1.

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The increase was partially offset by:

•$7 million in higher income tax expense primarily due to an increase in taxable earnings and lower tax credits primarily related to Oso Grande PTCs;

•$5 million in lower margin from wholesale transactions primarily due to a decrease in sales volume and price;

•$3 million in higher base operations and maintenance expenses primarily due to an increase in remote plant expenses due to insurance reimbursement credits not recurring in 2023 and an increase in outside service expenses;

•$3 million in higher net periodic non-service cost as a result of an increase in interest cost and a decrease in expected return on plan assets; and

•$3 million in lower transmission revenue due to recognition of revenue from a rate order settlement not recurring in 2023.

Performance - The first nine months of 2023 compared with the first nine months of 2022

We reported net income of $223 million in the first nine months of 2023 compared with net income of $194 million in the first nine months of 2022. The increase of $29 million, or 15%, was primarily due to:

•$23 million in higher retail revenue primarily due to: (i) higher usage as a result of favorable weather; (ii) an increase in rates as approved in the 2023 Rate Order; and (iii) higher LFCR revenues;

•$17 million in lower depreciation expense primarily due to the retirement of San Juan Unit 1;

•$9 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of favorable market conditions;

•$8 million in higher interest income due to an increase in interest earned on the PPFAC regulatory asset; and

•$5 million in higher AFUDC due to an increase in eligible construction expenditures.

The increase was partially offset by:

•$8 million in higher base operations and maintenance expenses primarily due to an increase in outside service expenses and costs at our generation facilities as a result of higher maintenance costs; partially offset by a decrease in remote plant expenses due to the retirement of San Juan Unit 1 in June 2022;

•$8 million in higher net periodic non-service cost as a result of an increase in interest cost and a decrease in expected return on plan assets;

•$8 million in higher income tax expense primarily due to an increase in taxable earnings and lower tax credits primarily related to Oso Grande PTCs; and

•$6 million in higher interest expense primarily due to the issuance of debt in February 2023.

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 in those matters.

2023 Rate Order

In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;

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•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% 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;

•approval to recover costs of changes in generation resources, including the addition of Oso Grande in rates; and

•denial of a request for a System Reliability Benefit adjustor that was designed to provide more timely recovery of our energy resource investments.

In January 2023, the ACC ordered that funding for the just and equitable transition away from fossil fuel-based economies for communities impacted by early coal-fired plant closures be considered as part of the 2023 Rate Order. In the 2023 Rate Order, the ACC determined that there was insufficient evidence to support customer funding for the just and equitable transition as part of the proceeding.

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% by 2035. In 2022, we issued an All-Source Request for Proposals (ASRFP), which requested new wind and solar generation, energy storage systems, and other resources such as energy efficiency resources. As part of the ASRFP, we received and are evaluating bids for all resource types. As a result of this process, we entered into an EPC agreement to develop a standalone BESS facility in September 2023. See Note 7 for additional information related to our commitment.

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 policies, 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. 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 are currently working on new long-term goals based on carbon emission reductions as part of our integrated resource plan which we plan to file with the ACC in November 2023.

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 taxable earnings. We recorded approximately $7 million and $16 million in PTCs related to Oso Grande, for the three and nine months ended September 30, 2023, respectively, and $11 million and $19 million, for the three and nine months ended September 30, 2022, respectively. The PTC rate published by the Internal Revenue Service for electricity produced by a qualified facility using wind placed in service prior to 2022 is $0.028 for 2023 and was $0.026 for 2022.

The PTCs offset most of the operating expenses of Oso Grande through August 2023. As of September 1, 2023, Oso Grande is included in rates as part of the 2023 Rate Order. 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.

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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 2022 Annual Report on Form 10-K and Part I, Item 3 of this Form 10-Q for information regarding interest rate risk and its impact on earnings.

RESULTS OF OPERATIONS

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

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

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

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

The following discussion provides the significant items that affected our results of operations in the third quarter and first nine months of 2023 compared with the same periods in 2022 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)	2023		2022		Percent		2023		2022		Percent
Operating Revenues
Retail	$	445	$	376	18.4	%	$	975	$	900	8.3	%
Wholesale, Short-Term (1)	73		114		(36.0)	%	209		223		(6.3)	%
Wholesale, Long-Term	18		30		(40.0)	%	60		72		(16.7)	%
Transmission	14		17		(17.6)	%	43		44		(2.3)	%
Springerville Units 3 and 4 Participant Billings	21		26		(19.2)	%	84		65		29.2	%
Other	22		24		(8.3)	%	76		60		26.7	%
Total Operating Revenues	$	593	$	587	1.0	%	$	1,447	$	1,364	6.1	%

(1)Includes revenue realized from wholesale trading as defined in the PPFAC plan of administration. We share 10% of any realized gains on trading transactions with retail customers through the PPFAC mechanism.

We reported Operating Revenues of $593 million in the third quarter of 2023 compared with $587 million in the same period for 2022. The increase of $6 million, or 1%, was primarily due to $69 million in higher retail revenue primarily due to: (i) higher PPFAC cost recoveries as a result of a higher PPFAC rate; (ii) higher usage as a result of favorable weather; and (iii) an increase in rates as approved in the 2023 Rate Order.

22

The increase was partially offset by:

•$41 million in lower short-term wholesale revenue primarily due to a decrease in price;

•$12 million in lower long-term wholesale revenue primarily due to a decrease in volume;

•$5 million in lower participant billings primarily related to Springerville Unit 4; and

•$3 million in lower transmission revenue due to recognition of revenue from a rate order settlement not recurring in 2023.

We reported Operating Revenues of $1,447 million for the first nine months of 2023 compared with $1,364 million in the same period for 2022. The increase of $83 million, or 6%, was primarily due to:

•$75 million in higher retail revenue primarily due to: (i) higher PPFAC cost recoveries as a result of an increase in PPFAC rates; (ii) higher usage as a result of favorable weather; and (iii) an increase in rates as approved in the 2023 Rate Order;

•$19 million in higher participant billings primarily related to Springerville Unit 3; and

•$16 million in higher other service revenue primarily due to an increase in market prices related to a natural gas transportation asset management agreement and higher LFCR revenue.

The increase was partially offset by:

•$14 million in lower short-term wholesale revenue primarily due to a decrease in price; and

•$12 million in lower long-term wholesale revenue primarily due to a decrease in volume.

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)	2023	2022	Percent		2023	2022	Percent
Electric Sales (kWh) (1)
Retail Sales	3,053	2,828	8.0	%	7,037	6,940	1.4	%
Wholesale, Long-Term	300	451	(33.5)	%	1,031	1,176	(12.3)	%
Wholesale, Short-Term	1,375	1,182	16.3	%	3,416	3,386	0.9	%
Total Electric Sales	4,728	4,461	6.0	%	11,484	11,502	(0.2)	%
Average Revenue per kWh (2)
Retail	14.55	13.30	9.4	%	13.85	12.97	6.8	%
Wholesale, Long-Term	6.32	6.60	(4.2)	%	5.87	6.14	(4.4)	%
Wholesale, Short-Term	5.18	9.63	(46.2)	%	5.58	6.32	(11.7)	%
Total Retail Customers (3)					445,952	442,104	0.9	%

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

(2)This metric represents the 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.

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

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Operating Expenses

Fuel and Purchased Power Expense

We reported Fuel and Purchased Power expense of $243 million in the third quarter of 2023 compared with $259 million in the same period for 2022. The decrease of $16 million, or 6%, was primarily due to $39 million in lower Fuel Expense due to a decrease in natural gas prices; partially offset by higher realized losses on natural gas swaps and an increase in Gas-Fired Generation volumes.

The decrease was partially offset by:

•$13 million increase in PPFAC Recovery Treatment; partially offset by an increase in PPFAC eligible costs deferred as a regulatory asset for future recovery; and

•$8 million in higher Purchased Power Expense primarily due to an increase in price.

We reported Fuel and Purchased Power expense of $582 million for the first nine months of 2023 compared with $555 million for the same period for 2022. The increase of $27 million, or 5%, was primarily due to a $61 million increase in PPFAC Recovery Treatment and a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery. The increase was partially offset by $39 million in lower Fuel Expense primarily due to a decrease in natural gas prices net of higher realized losses on natural gas swaps.

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)	2023	2022	Percent		2023	2022	Percent
Sources of Energy
Coal-Fired Generation	1,099	1,072	2.5	%	2,674	3,718	(28.1)	%
Gas-Fired Generation	2,373	1,987	19.4	%	5,788	4,791	20.8	%
Utility-Owned Renewable Generation	148	168	(11.9)	%	571	645	(11.5)	%
Total Generation	3,620	3,227	12.2	%	9,033	9,154	(1.3)	%
Purchased Power, Non-Renewable	1,040	1,161	(10.4)	%	1,830	1,901	(3.7)	%
Purchased Power, Renewable	311	270	15.2	%	1,085	1,016	6.8	%
Total Generation and Purchased Power (1)	4,971	4,658	6.7	%	11,948	12,071	(1.0)	%

(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal	3.06	3.04	0.7	%	3.04	2.71	12.2	%
Natural Gas (3)	2.70	4.83	(44.1)	%	3.48	4.41	(21.1)	%
Average Cost of Purchased Power (4)
Purchased Power, Non-Renewable	8.49	7.73	9.8	%	7.15	7.20	(0.7)	%
Purchased Power, Renewable	6.79	7.03	(3.4)	%	6.73	6.79	(0.9)	%

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

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

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

(4)This metric represents 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

We reported Operations and Maintenance expense of $104 million in the third quarter of 2023 compared with $98 million in the same period for 2022. The increase of $6 million, or 6%, was primarily due to:

•$5 million in higher RES and DSM expenses; and

•$3 million in higher generation operations and outside service expenses.

The increase was partially offset by $2 million in lower reimbursable maintenance related to Springerville Unit 4.

We reported Operations and Maintenance expense of $332 million for the first nine months of 2023 compared with $296 million for the same period for 2022. The increase of $36 million, or 12%, was primarily due to:

•$19 million in higher reimbursable maintenance expense related to Springerville Unit 3 primarily due to planned outages; partially offset by lower reimbursable maintenance related to Springerville Unit 4;

•$9 million in higher RES and DSM expenses; and

•$5 million in higher generation operations and outside service expenses.

Depreciation and Amortization Expense

We reported Depreciation and Amortization expense of $59 million in the third quarter of 2023 compared with $65 million in the same period for 2022. The decrease of $6 million, or 9%, was primarily due to the retirement of San Juan Unit 1.

We reported Depreciation and Amortization expense of $173 million for the first nine months of 2023 compared with $193 million for the same period for 2022. The decrease of $20 million, or 10%, was primarily due to the retirement of San Juan Unit 1.

Other Income (Expense)

We reported other expenses of $18 million in the third quarter of 2023 compared with $16 million in the same period for 2022. The increase of $2 million, or 13%, was primarily due to:

•$3 million in higher net periodic non-service cost primarily due to an increase in interest cost and a decrease in expected return on plan assets; and

•$3 million in higher interest expense primarily due to the issuance of debt in February 2023.

The increase was partially offset by:

•$2 million in higher interest income primarily due to an increase in interest earned on the PPFAC regulatory asset; and

•$2 million in higher AFUDC due to an increase in eligible construction work in process balances.

We reported other expenses of $50 million for the first nine months of 2023 compared with $53 million for the same period for 2022. The decrease of $3 million, or 6%, was primarily due to:

•$9 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of favorable market conditions; and

•$9 million in higher interest income primarily due to an increase in interest earned on the PPFAC regulatory asset.

The decrease was partially offset by:

•$9 million in higher net periodic non-service cost primarily due to an increase in interest cost and a decrease in expected return on plan assets; and

•$8 million in higher interest expense primarily due to the issuance of debt in February 2023.

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Income Tax Expense

We reported Income Tax Expense of $23 million in the third quarter of 2023 compared with $14 million in the same period for 2022. The increase of $9 million, or 64%, was primarily due to:

•$4 million in higher tax expense due to an increase in taxable earnings; and

•$3 million in lower tax credits primarily related to Oso Grande PTCs.

We reported Income Tax Expense of $36 million for the first nine months of 2023 compared with $24 million for the same period for 2022. The increase of $12 million, or 50%, was primarily due to:

•$10 million in higher tax expense due to an increase in taxable earnings; and

•$3 million in lower tax credits primarily related to Oso Grande PTCs.

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 our summer peaking load. Market risks associated with fluctuations in commodity prices can temporarily affect our cash flows due to timing of recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. 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, 2023
Cash and Cash Equivalents	$	138
Amount Available under Revolving Credit Agreement (1)	250
Total Liquidity	$	388

(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 below.

Future Liquidity Requirements

We expect to meet all of our short-term 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 contractual 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 our 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 our 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)	2023		2022		Percent
Operating Activities	$	428	$	438	(2.3)	%
Investing Activities	(388)		(337)		15.1	%
Financing Activities	80		43		86.0	%
Net Increase (Decrease)	120		144		(16.7)	%
Beginning of Period	51		33		54.5	%
End of Period	$	171	$	177	(3.4)	%

Operating Activities

Net cash flows provided by operating activities decreased by $10 million in the first nine months of 2023 compared with the same period in 2022. The decrease was primarily due to: (i) changes in working capital due to a decrease in wholesale energy balances primarily due to lower prices; partially offset by the timing of billing collections; (ii) cash collateral deposits received from counterparties in 2022, not recurring in 2023; and (iii) higher base operations and maintenance expenses. The decrease was partially offset by an increase in retail revenue due to: (i) higher PPFAC cost recoveries as a result of an increase in PPFAC rates; (ii) higher usage as a result of favorable weather; and (iii) an increase in rates as approved in the 2023 Rate Order.

Investing Activities

Net cash flows used for investing activities increased by $51 million in the first nine months of 2023 compared with the same period in 2022 primarily due to an increase in cash paid for capital expenditures.

Financing Activities

Net cash flows provided by financing activities increased by $37 million in the first nine months of 2023 compared with the same period in 2022 primarily due to a decrease in: (i) dividends declared and paid to UNS Energy; and (ii) repayments of credit facility borrowings.

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, 2023, our short-term investments were deposited in insured cash sweep and money market accounts.

Access to Credit

We have access to working capital through our credit agreement with lenders. Amounts borrowed from the 2021 Credit Agreement are used for working capital and other general corporate purposes. LOCs may be issued from time to time to support energy procurement, hedging transactions, and other business activities.

•In June 2023, the 2021 Credit Agreement was amended to provide for the transition to SOFR-based borrowings.

•A $5 million LOC outstanding as of December 31, 2022, was cancelled in August 2023.

See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding our 2021 Credit Agreement and Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2022 Annual Report on Form 10-K 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 our financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt

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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.

We have, from time to time, refinanced or repurchased portions of our outstanding debt before scheduled maturity.

•In February 2023, we issued and sold $375 million aggregate principal amount of 5.50% senior unsecured notes due April 2053. We used the net proceeds to redeem and repay debt and for general corporate purposes.

•In March 2023, we repaid at maturity $150 million aggregate principal amount of 3.85% senior unsecured notes.

•In March 2023, we redeemed at par prior to maturity $91 million aggregate principal amount of tax-exempt bonds bearing interest at a rate of 4.00% per annum.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2023, 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 our 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 our 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 we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2023, we were 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

We received no equity contributions in the third quarter of 2023 and received an equity contribution of $6 million in the first nine months of 2023. We received no equity contributions in the third quarter or first nine months of 2022.

Dividends Declared and Paid to Parent

We did not declare or pay dividends to UNS Energy in the third quarter of 2023 and declared and paid $55 million in dividends to UNS Energy in the first nine months of 2023. We declared and paid $75 million in dividends to UNS Energy in the third quarter and first nine months of 2022. On October 26, 2023, TEP declared a dividend of up to $15 million to be paid to UNS Energy on or before December 31, 2023.

Master Trading Agreements

We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of September 30, 2023, we 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

Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. We prioritize 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 2023 were $345 million.

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

	Years Ended December 31,
(in millions)	2023		2024		2025		2026		2027
Generation Facilities:
New Energy Resources (1)	$	192	$	188	$	185	$	283	$	550
Other Generation Facilities (2)	154		33		41		22		60
Total Generation Facilities	346		221		226		305		610
Transmission and Distribution (3)	343		409		258		238		237
General and Other (4)	93		63		64		77		66
Total Capital Expenditures	$	782	$	693	$	548	$	620	$	913

(1)Includes investments in renewable energy and BESS facilities, in alignment with our long-term strategy of transitioning to a more sustainable energy portfolio. In September 2023, TEP entered into an EPC agreement to develop a standalone BESS facility at a cost of $294 million. 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 EPC agreement.

(2)Includes investments in existing facilities, including upgrades and ongoing maintenance to ensure reliability.

(3)Investments in transmission capacity and distribution system reliability.

(4)Includes costs 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, including inflationary pressures, construction schedules, labor shortages and/or labor strikes, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, new or changing commitments, 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

Among other provisions included in the IRA, the legislation enacted a new Corporate Alternative Minimum Tax (CAMT) of 15% that is effective for tax years beginning after December 31, 2022. We are currently subject to the CAMT due to our membership in the Fortis consolidated tax group. We are currently assessing this legislation and do not expect a material impact on our financial results.

Under the terms of the tax sharing agreement with UNS Energy, we received $1 million in net tax sharing payments for the first nine months of 2023 and made $2 million in tax sharing payments for the first nine months of 2022. Future cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.

Collective Bargaining Agreements

In June 2023, the International Brotherhood of Electrical Workers Local No. 1116 ratified a new collective bargaining agreement with TEP set to expire on June 30, 2028.

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

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operating efficiency and increase capital and operating costs. We expect recovery of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.

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 (Regional Haze). The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a State Implementation Plan (SIP) and must review and submit revisions to the SIP on a periodic basis.

In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The Arizona Department of Environmental Quality (ADEQ) began to develop a control strategy with a focus on making reasonable progress toward the national visibility goal. In July 2019, we were notified by ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluation.

We conducted the potential emissions controls evaluation, commonly referred to as the four factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP. In August 2022, the ADEQ submitted the revised SIP to the EPA, and 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 timeframes, we anticipate that compliance strategies, if any, will likely be required to be implemented one year following EPA approval of ADEQ's revised SIP. We cannot predict the outcome of this matter but will continue to work with the ADEQ 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 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 in June 2022, reversed the D.C. Circuit and remanded the cases back for further proceedings.

In May 2023, the EPA published a proposed GHG rule addressing GHG emissions from fossil fuel-fired electric generating units. The proposed rule also provides for the repeal of the ACE rule. Public comment closed on August 8, 2023. We are analyzing the EPA's proposed rule and cannot predict the outcome of this rulemaking at this time.

Coal Combustion Residuals Regulation

In April 2015, the EPA published final rules effective October 2015, which established technical requirements for Coal Combustion Residuals (CCR) landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The CCR rules provide for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. Arizona Public Service Company, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility.

In May 2023, the EPA published a proposal that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. EPA proposes to establish two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCR management units which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. As proposed, a CCR management unit would include not only historically closed landfills and surface impoundments, but also prior applications of CCR on land such as for structural fill. The EPA expects to finalize this proposal by spring of 2024.

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We are analyzing the EPA’s pending proposals and cannot predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending. At this time, we do not anticipate our share of the cost to complete any corrective actions to close the CCR disposal units, or to gather and perform remedial evaluations on groundwater at Four Corners Units 4 and 5, will have a significant impact on our operations, financial position, or cash flows.

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, 2023, 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 2022 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED OR 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 2022 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the SEC’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, 2023. There was no change in TEP’s internal control over financial reporting during the quarter ended September 30, 2023, 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.

Pursuant to Item 103 of Regulation S-K under the Exchange Act, TEP is required to disclose certain information about environmental proceedings to which a governmental authority is a party if TEP reasonably believes such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. TEP has elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.

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 2022 Annual Report on Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2022 Annual Report on Form 10-K.

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ITEM 6. EXHIBITS

EXHIBIT INDEX
Exhibit No.	Description
*31(a)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Susan M. Gray
*31(b)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Frank P. Marino
**32	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
104	The cover page from TEP's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, formatted in Inline XBRL and contained in Exhibit 101

*	Filed herewith.
**	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.

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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 26, 2023	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President, Chief Financial Officer, and Director
		(Principal Financial Officer)

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