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 ~~March~~June 3130, 2024

☐ 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 ~~April~~July 30, 2024.

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			1819
Critical Accounting Estimates			2830
New Accounting Standards Issued and Not Yet Adopted			2830
Item 3. Quantitative and Qualitative Disclosures about Market Risk			2830
Item 4. Controls and Procedures			2830
PART II
Item 1. Legal Proceedings			3032
Item 1A. Risk Factors			3032
Item 6. Exhibits			3133
Signatures			3234

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

2023 IRP						TEP's 2023 Integrated Resource Plan which outlines TEP's aspirational goal to reach net zero direct greenhouse gas emissions by 2050
2020 IRP						TEP's 2020 Integrated Resource Plan which outlines TEP's plan to reduce its carbon emissions by 80% compared to 2005 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
ACC						Arizona Corporation Commission
ADEQ						Arizona Department of Environmental Quality
AFUDC						Allowance for Funds Used During Construction
BESS						Battery Energy Storage System
CCR						Coal Combustion Residuals
DG						Distributed Generation
DSM						Demand Side Management
EDIT						Excess Deferred Income Taxes
EPA						Environmental Protection Agency
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
REC						Renewable Energy 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
SIP						State Implementation Plan
TCA						Transmission Cost Adjustor

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 Power Plant
Navajo						Navajo Generating Station
Oso Grande						A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico
Roadrunner Reserve I						A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in the second half of 2025
San Juan						San Juan Generating Station
Springerville						Springerville Generating Station
SRP						Salt River Project Agricultural Improvement and Power District
Sundt						H. Wilson Sundt Generating Station
TEP						Tucson Electric Power Company, the principal subsidiary of UNS Energy
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)
GWh						Gigawatt-hour(s)
kWh						Kilowatt-hour(s)
MW						Megawatt(s)
MWh						Megawatt-hour(s)

iii

Table of Contents

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. TEP, or the Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as "anticipates," "believes," "estimates," "expects," "intends," "aspires," "may," "plans," "predicts," "potential," "projects," "would," "strategy," 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 2023 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 Energy Imbalance Market; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality, ~~and~~ extreme weather events, and wildfires, affecting electricity usage of our customers, operational performance, and operating and capital costs to ensure system reliability; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the 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~~volatile 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 EPC agreements to develop standalone battery energy storage facilities, 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 2050, 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~~arise 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 crisis 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 implementation of our 2023 IRP.

Table of Contents

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)

			Three Months Ended March 31,
	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Operating Revenues	$	429,546	$	418,236	$	~~452~~882,~~756~~302	$	~~435~~854,~~853~~089
Operating Expenses
Fuel	63,648		64,630		~~101~~165,~~454~~102		~~124~~188,~~070~~700
Purchased Power	27,440		47,136		2653,~~230~~670		3683,~~440~~576
Transmission and Other PPFAC Recoverable Costs	15,389		15,362		1833,~~078~~467		1631,~~599~~961
Increase (Decrease) to Reflect PPFAC Recovery Treatment	38,467		26,583		3271,~~768~~235		734,~~914~~497
Total Fuel and Purchased Power	144,944		153,711		~~178~~323,~~530~~474		~~185~~338,~~023~~734
Operations and Maintenance	105,517		119,983		~~118~~224,~~749~~266		~~108~~228,~~059~~042
Depreciation	56,367		47,424		55111,~~604~~971		4794,~~140~~564
Amortization	7,773		9,803		715,~~736~~509		919,~~691~~494
Taxes Other Than Income Taxes	17,493		17,103		1836,~~752~~245		1734,~~277~~380
Total Operating Expenses	332,094		348,024		~~379~~711,~~371~~465		~~367~~715,~~190~~214
Operating Income	97,452		70,212		73170,~~385~~837		68138,~~663~~875
Other Income (Expense)
Interest Expense	(24,248)		(24,172)		(2448,~~005~~253)		(2347,~~316~~488)
Allowance For Borrowed Funds	1,877		1,161		13,~~876~~753		12,~~008~~169
Allowance For Equity Funds	5,407		3,249		510,~~252~~659		26,~~893~~142
Unrealized Gains (Losses) on Investments	128		433		~~862~~990		1,~~360~~793
Other, Net	421		3,666		1,~~296~~716		25,~~091~~757
Total Other Income (Expense)	(16,415)		(15,663)		(1431,~~720~~135)		(1531,~~964~~627)
Income Before Income Tax Expense	81,037		54,549		58139,~~665~~702		52107,~~699~~248
Income Tax Expense	10,603		6,823		718,~~484~~087		512,~~806~~629
Net Income	$	70,434	$	47,726	$	51121,~~181~~615	$	4694,~~893~~619

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
	Six Months Ended June 30,
	2024		2023
Cash Flows from Operating Activities
Net Income	$	51121,~~181~~615	$	4694,~~893~~619
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	55111,~~604~~971		4794,~~140~~564
Amortization Expense	715,~~736~~509		919,~~691~~494
Amortization of Debt Issuance Costs	~~763~~1,526		~~782~~1,541
Use of Renewable Energy Credits for Compliance	1123,~~984~~985		1122,~~402~~608
Deferred Income Taxes	513,~~590~~248		49,~~657~~915
Pension and Other Postretirement Benefits Expense	49,~~510~~019		37,~~794~~588
Pension and Other Postretirement Benefits Funding	(~~953~~5,762)		(14,~~186~~727)
Allowance for Equity Funds Used During Construction	(510,~~252~~659)		(26,~~893~~142)
Changes in Current Assets and Current Liabilities:
Accounts Receivable	26(12,~~817~~518)		~~133~~108,~~058~~638
Materials, Supplies, and Fuel Inventory	(317,~~350~~071)		(1018,~~040~~147)
Regulatory Assets	4849,~~234~~894		~~294~~22,679
Other Current Assets	~~(1,930)~~326		~~(887)~~859
Accounts Payable and Accrued Charges	242,~~007~~894		(~~104~~118,~~341~~955)
Income Taxes Receivable/Payable	(~~688~~426)		(~~777~~1,086)
Regulatory Liabilities	(322,~~703)~~297		(23,~~818~~219)
Other, Net	(30,~~448~~165)		(1314,~~858~~877)
Net Cash Flows—Operating Activities	~~190~~295,~~102~~683		~~120~~215,~~911~~352
Cash Flows from Investing Activities
Capital Expenditures	(~~133~~265,~~283~~330)		(~~116~~231,~~683~~472)
Purchase Intangibles, Renewable Energy Credits	(1130,~~956~~478)		(1231,~~961~~718)
Contributions in Aid of Construction	~~965~~(263)		~~799~~2,539
Net Cash Flows—Investing Activities	(~~144~~296,~~274~~071)		(~~128~~260,~~845~~651)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	1525,000		—
Repayments of Borrowings, Revolving Credit Facility	(1525,000)		—
Proceeds from Issuance, Long-Term Debt—Net of Discount	—		373,954
Repayments of Long-Term Debt	—		(240,745)
Payment of Debt Issuance Costs	—		(3,738)
Dividend Paid to Parent	—		(55,000)
Payment of Debt Issuance Costs	—		(4,092)
Contribution from Parent	—		5,900
Other, Net	~~317~~1,426		(~~560~~877)
Net Cash Flows—Financing Activities	~~317~~1,426		~~134~~79,~~811~~140
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	461,~~145~~038		~~126~~33,~~877~~841
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	42,595		50,981
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	8843,~~740~~633	$	~~177~~84,~~858~~822

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	March 31, 2024		December 31, 2023
	June 30, 2024		December 31, 2023
ASSETS
Utility Plant
Plant in Service	$	8,~~099~~222,~~577~~367	$	8,035,444
Construction Work in Progress	~~531~~504,~~459~~888		475,391
Total Utility Plant	8,~~631~~727,~~036~~255		8,510,835
Accumulated Depreciation and Amortization	(2,~~605~~647,~~695~~300)		(2,570,157)
Total Utility Plant, Net	6,~~025~~079,~~341~~955		5,940,678
Investments and Other Property	6966,~~130~~774		70,080
Current Assets
Cash and Cash Equivalents	5714,~~297~~798		8,616
Accounts Receivable (Net of Allowance for Credit Losses of $11,263 and $11,676)	192,799		217,381
Accounts Receivable (Net of Allowance for Credit Losses of $11,684 and $11,676 as of June 30, 2024 and December 31, 2023, respectively)	229,531		217,381
Fuel Inventory	2735,~~237~~871		34,475
Materials and Supplies	~~179~~184,~~825~~911		172,667
Regulatory Assets	~~112~~104,~~782~~927		147,389
Derivative Instruments	3130,~~487~~771		3,091
Other	3230,~~381~~125		30,450
Total Current Assets	~~633~~630,~~808~~934		614,069
Regulatory Assets	~~195~~199,~~953~~545		182,997
Derivative Instruments	2930,~~675~~179		31,614
Other Noncurrent Assets	~~136~~141,~~232~~271		134,196
Total Assets	$	7,~~090~~148,~~139~~658	$	6,973,634

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	March 31, 2024		December 31, 2023
	June 30, 2024		December 31, 2023
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2024 and December 31, 2023)	$	1,696,539	$	1,696,539
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2024 and December 31, 2023)	$	1,696,539	$	1,696,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	1,~~214~~284,~~102~~536		1,162,921
Accumulated Other Comprehensive Loss	(3,~~783~~737)		(3,829)
Total Common Stock Equity	2,~~900~~970,~~501~~981		2,849,274
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2024 and December 31, 2023)	—		—
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2024 and December 31, 2023)	—		—
Long-Term Debt, Net	2,097,~~399~~807		2,396,542
Total Capitalization	45,~~997~~068,~~900~~788		5,245,816
Current Liabilities
Current Maturities of Long-Term Debt, Net	299,~~647~~743		—
Accounts Payable	~~145~~137,~~357~~106		137,002
Accrued Taxes Other than Income Taxes	7256,~~813~~519		57,291
Accrued Employee Expenses	2931,~~816~~423		39,466
Accrued Interest	2816,~~463~~307		16,541
Regulatory Liabilities	91117,~~737~~548		92,740
Customer Deposits	15,~~802~~675		15,833
Derivative Instruments	4035,~~848~~829		25,828
Other	4244,~~523~~202		36,312
Total Current Liabilities	~~767~~754,~~006~~352		421,013
Deferred Income Taxes, Net	~~656~~669,~~906~~512		647,730
Regulatory Liabilities	~~391~~378,~~492~~713		396,061
Pension and Other Postretirement Benefits	8381,~~515~~934		81,241
Derivative Instruments	5,~~654~~636		4,338
Other Noncurrent Liabilities	~~187~~189,~~666~~723		177,435
Total Liabilities	2,~~092~~079,~~239~~870		1,727,818
Commitments and Contingencies
Total Capitalization and Liabilities	$	7,~~090~~148,~~139~~658	$	6,973,634

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

(Concluded)

TUCSON ELECTRIC POWER COMPANY

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

(Amounts in thousands)

	Three Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2022	$	1,696,539	$	(6,357)	$	968,367	$	(2,884)	$	2,655,665
Net Income					46,893				46,893
Other Comprehensive Income (Loss), Net of Tax							28		28
Contribution from Parent	5,900								5,900
Balances as of March 31, 2023	$	1,702,439	$	(6,357)	$	1,015,260	$	(2,856)	$	2,708,486
Net Income					47,726				47,726
Other Comprehensive Income (Loss), Net of Tax							27		27
Dividend Declared to Parent					(55,000)				(55,000)
Balances as of June 30, 2023	$	1,702,439	$	(6,357)	$	1,007,986	$	(2,829)	$	2,701,239

Balances as of December 31, 2023	$	1,696,539	$	(6,357)	$	1,162,921	$	(3,829)	$	2,849,274
Net Income					51,181				51,181
Other Comprehensive Income (Loss), Net of Tax							46		46
Balances as of March 31, 2024	$	1,696,539	$	(6,357)	$	1,214,102	$	(3,783)	$	2,900,501
Net Income					70,434				70,434
Other Comprehensive Income (Loss), Net of Tax							46		46
Balances as of June 30, 2024	$	1,696,539	$	(6,357)	$	1,284,536	$	(3,737)	$	2,970,981


	Six Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2022	$	1,696,539	$	(6,357)	$	968,367	$	(2,884)	$	2,655,665
Net Income					94,619				94,619
Other Comprehensive Income (Loss), Net of Tax							55		55
Dividend Declared to Parent					(55,000)				(55,000)

Contribution from Parent	5,900								5,900
Balances as of June 30, 2023	$	1,702,439	$	(6,357)	$	1,007,986	$	(2,829)	$	2,701,239


Balances as of December 31, 2023	$	1,696,539	$	(6,357)	$	1,162,921	$	(3,829)	$	2,849,274
Net Income					121,615				121,615
Other Comprehensive Income (Loss), Net of Tax							92		92



Balances as of June 30, 2024	$	1,696,539	$	(6,357)	$	1,284,536	$	(3,737)	$	2,970,981

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

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 450,000 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 2023 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 ~~March~~June 3130, 2024, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term renewable PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Restricted Cash

Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in 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:

	Three Months Ended March 31,
	Six Months Ended June 30,
(in millions)	2024		2023
Cash and Cash Equivalents	$	5715	$	~~144~~53
Restricted Cash included in:
Investments and Other Property	2219		2119
Current Assets—Other	10		13
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	8944	$	~~178~~85

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 $46 million and $10 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and six months ended ~~March~~June 3130, 2024, respectively, and $4 million and $9 million for the three and six months ended June 30, 2023, respectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) and the SEC has not yet been adopted and is not reflected in TEP’s financial statements. Unless otherwise indicated, TEP is assessing the impact such guidance may have on TEP’s financial position, results of operations, cash flows, and disclosures.

Income Tax Disclosures

In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance ~~should~~is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures.

Reportable Segment Disclosures

In November 2023, the FASB issued accounting guidance that requires disclosure of significant segment expenses and new disclosures for entities with a single reportable segment. The amendments are effective for annual periods beginning on January 1, 2024 and interim periods beginning on January 1, 2025 and are to be applied retrospectively. Early adoption is permitted.

Climate-Related Disclosures

In March 2024, the SEC issued a final rule that requires disclosure of: (i) financial statement impacts of severe weather events and other natural conditions; (ii) a roll forward of carbon offset and REC balances if material to the Company's plan to achieve climate-related targets or goals; and (iii) material impacts on estimates and assumptions in the financial statements. The rule is effective for TEP for annual periods beginning January 1, 2027 and is to be applied prospectively. In April 2024, the SEC issued an order staying the final rule pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit. TEP cannot predict what, if any, changes in scope or timing may occur as a result of the pending litigation. TEP continues its assessment to prepare for the new rule.

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 the ~~Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.~~

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Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual approved costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. 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 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 May 2023, the ACC approved a rate adjustment designed to collect the then under-recovered PPFAC balance over 12 months.~~

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

			Three Months Ended March 31,
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Beginning of Period	$	7	$	118	$	55	$	124
Deferred Fuel and Purchased Power Costs (1)	58		65		49107		58123
PPFAC and Base Power Recoveries	(96)		(90)		(97193)		(64154)
End of Period	$	(31)	$	93	$	7(31)	$	~~118~~93

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

Transmission Cost Adjustor

The TCA allows for timely recovery or refund of actual costs, net of applicable credits, 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~~net ~~OATT~~costs ~~formula~~required ~~rate~~to provide transmission services to retail customers. 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% of the annual energy requirement. The renewable energy requirement in 2024 is 14% of retail electric sales. Consistent with prior years, TEP plans 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 amount funds: (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 TEP's extension of the 2021 RES implementation plan through 2024.

In ~~March~~May 2024, ~~TEP filed a proposal with~~ the ACC toapproved an increase to the RES tariff to ~~account~~recover ~~for~~ under-collected RES funds totaling ~~approximately~~ $17 million. asThe ofACC ~~December~~also ~~31,~~waived ~~2023~~for TEP the general requirement that Arizona utilities file a RES implementation plan on an annual basis.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs 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 cumulative three-year budget of $72 million, which is collected through the DSM surcharge. In ~~January~~May 2024, ~~TEP filed a proposal with~~ the ACC toapproved ~~refund~~refunding over-collected, uncommitted DSM surcharge funds totaling $10 million over ~~a period not to exceed one year beginning in~~ the ~~first~~June ~~half~~and ofJuly 2024 billing periods.

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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 based on an estimate of lost retail kWh sales during the period. 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.

REGULATORY ASSETS AND LIABILITIES

($ in millions)	Remaining Recovery Period(years)	March 31, 2024		December 31, 2023
Regulatory Assets
Pension and Other Postretirement Benefits (Note 7)	Various	$	106	$	107
Early Generation Retirement Costs	Various	47		48
Derivatives (Note 8)	6	40		26
Lost Fixed Cost Recovery	1	33		35
Property Tax Deferrals (1)	1	30		30
Final Mine Reclamation and Retiree Healthcare Costs (2)	16	21		6
Under-Recovered Purchased Energy Costs	1	7		55
Income Taxes Recoverable through Future Rates (3)	Various	6		6
Unamortized Loss on Reacquired Debt	Various	5		5
Other Regulatory Assets	Various	14		12
Total Regulatory Assets		309		330
Less Current Portion	1	113		147
Total Noncurrent Regulatory Assets		$	196	$	183

Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	225	$	229
Net Cost of Removal (4)	Various	132		130
Renewable Energy Standard	Various	76		77
Derivatives (Note 8)	6	28		28
Demand Side Management	1	10		9
Deferred Investment Tax Credits	Various	6		6
Pension and Other Postretirement Benefits (Note 7)	Various	4		4
Transmission Revenue Requirement Balancing Account	1	2		5
Other Regulatory Liabilities	Various	—		1
Total Regulatory Liabilities		483		489
Less Current Portion	1	92		93
Total Noncurrent Regulatory Liabilities		$	391	$	396

(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.

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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)	June 30, 2024		December 31, 2023
Regulatory Assets
Pension and Other Postretirement Benefits (Note 7)	Various	$	104	$	107
Early Generation Retirement Costs	Various	52		48
Derivatives (Note 8)	6	34		26
Lost Fixed Cost Recovery	1	34		35
Property Tax Deferrals (1)	1	30		30
Final Mine Reclamation (2)	16	21		6

Income Taxes Recoverable through Future Rates (3)	Various	5		6
Unamortized Loss on Reacquired Debt	Various	5		5

Under-Recovered Purchased Energy Costs	1	—		55
Other Regulatory Assets	Various	20		12
Total Regulatory Assets		305		330
Less Current Portion	1	105		147
Total Noncurrent Regulatory Assets		$	200	$	183


Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	220	$	229
Net Cost of Removal (4)	Various	123		130
Renewable Energy Standard	Various	75		77
Over-Recovered Purchased Energy Costs	1	31		—
Derivatives (Note 8)	6	28		28
Demand Side Management	1	8		9
Deferred Investment Tax Credits	Various	6		6
Pension and Other Postretirement Benefits (Note 7)	Various	4		4
Transmission Revenue Requirement Balancing Account	1	—		5



Other Regulatory Liabilities	Various	2		1



Total Regulatory Liabilities		497		489
Less Current Portion	1	118		93
Total Noncurrent Regulatory Liabilities		$	379	$	396

(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 2040. San Juan Unit 1 was retired in 2022. In March 2024, the San Juan reclamation oversight committee approved a new final mine reclamation study which resulted in a $15 million increase in the final mine reclamation regulatory asset.

(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.

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 Fuel and Purchased ~~Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.~~

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority 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 March 31,
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Retail	$	334	$	297	$	~~282~~616	$	~~233~~530
Wholesale	51		64		89140		~~126~~190
Other Services	27		39		3966		3170
Revenues from Contracts with Customers	412		400		~~410~~822		~~390~~790
Alternative Revenues	11		8		919		1321
Other	7		10		3441		3343
Total Operating Revenues	$	430	$	418	$	~~453~~882	$	~~436~~854

NOTE 4. ACCOUNTS RECEIVABLE

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

(in millions)	~~March~~June 3130, 2024		December 31, 2023
Retail	$	89111	$	109
Retail, Unbilled	4779		57
Retail, Allowance for Credit Losses	(1112)		(12)
Wholesale (1)	29		37
Due from Affiliates (Note 5)	138		7
Other	2615		19
Accounts Receivable	$	~~193~~230	$	217

(1)Includes $58 million as of ~~March~~June 3130, 2024, and $10 million as of December 31, 2023, of receivables related to revenue from derivative instruments.

10ALLOWANCE FOR CREDIT LOSSES

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Beginning of Period	$	(11)	$	(8)	$	(12)	$	(9)
Credit Loss Expense	(2)		(1)		(3)		(2)
Write-offs	1		—		3		2

End of Period	$	(12)	$	(9)	$	(12)	$	(9)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

ALLOWANCE FOR CREDIT LOSSES

	Three Months Ended March 31,
(in millions)		2024		2023
Beginning of Period		$	(12)	$	(9)
Credit Loss Expense		(1)		(1)
Write-offs		2		2
End of Period		$	(11)	$	(8)

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)	~~March~~June 3130, 2024		December 31, 2023
Receivables from Related Parties
UNS Energy	$	6	$	—
UNS Electric	$	6	$	5
UNS Electric	5		5
UNS Gas	2		2
Total Due from Related Parties	$	138	$	7
Payables to Related Parties
UNS Energy	$	52	$	1
UNS Electric	1		1
UNS Gas	—		1
Total Due to Related Parties	$	63	$	3

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

			Three Months Ended March 31,
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Goods and Services Provided by TEP to Affiliates
Common Costs, UNS Energy Affiliates (1)	$	6	$	5	$	612	$	611
Transmission Revenues, UNS Electric (2)	2		2		24		24
Wholesale Revenues, UNS Electric (2)	1		6		23		713
Control Area Services, UNS Electric (3)	1		1		1		1
Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (3)					$	3	$	3
Corporate Services, UNS Energy (4)	$	2	$	1	$	5	$	4
Capacity Charges, UNS Gas (4)					1		1
Corporate Services, UNS Energy Affiliates (5)	1		1		1		1
Purchased Power, UNS Electric (2)					—		1
Capacity Charges, UNS Gas (6)	—		—		1		1
Purchased Power, UNS Electric (2)	—		—		—		1

(1)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.

11(2)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.

(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 $4 million for the three and six months ended June 30, 2024 and 2023, 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.

DIVIDEND DECLARED TO PARENT

On July 25, 2024, TEP declared a dividend of up to $85 million to be paid to UNS Energy on or before December 31, 2024.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(2)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.

(3)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 in each of the three months ended March 31, 2024 and 2023.

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

NOTE 6. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2023 Annual Report on Form 10-K.

CONTINGENCIES

Legal Matters

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

Mine Reclamation at Generation Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation costs are subject to various assumptions, such as: estimations of reclamation costs; timing of when final reclamation will occur; and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP’s PPFAC allows the 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~~records ~~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 for the mines at 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 2022. In March 2024, TEP increased the San Juan final mine reclamation liability by $15 million as a result of a new final mine reclamation study. As of ~~March~~June 3130, 2024, TEP’s remaining final mine reclamation liability at San Juan was $3836 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2040. See Note 1 for additional information on restricted cash relating to TEP's share of final mine reclamation and decommissioning costs at San Juan.

TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation totaled $4240 million and $29 million as of ~~March~~June 3130, 2024, and December 31, 2023, respectively, and was recorded in Other Noncurrent Liabilities 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 maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of ~~March~~June 3130, 2024, there have been no such payment defaults under either of the participation agreements.

12The 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

~~The~~waste ~~Navajo~~disposal, ~~Generating~~protected ~~Station~~species, and ~~San~~other ~~Juan~~environmental ~~participation~~matters ~~agreements~~that ~~expired~~have inthe ~~2019~~potential to impact TEP's current and ~~2022,~~future ~~respectively~~operations. Environmental laws and regulations are subject to a range of interpretations, ~~but~~which ~~certain~~may ~~performance~~ultimately ~~obligations~~be resolved by the courts. Because these laws and regulations continue ~~through~~to evolve, TEP is unable to predict the ~~decommissioning~~impact of ~~both~~the ~~generation~~changing ~~facilities~~laws and regulations on its operations and consolidated financial results. InTEP expects to recover the ~~case~~cost of aenvironmental ~~default~~compliance ~~under~~from ~~either~~its ~~participation~~customers. ~~agreement,~~TEP ~~the~~believes ~~non-defaulting~~it ~~participants~~is ~~would~~in ~~seek~~compliance ~~financial~~with ~~recovery~~applicable ~~directly~~environmental ~~from~~laws ~~the~~and ~~defaulting~~regulations ~~party~~in all material respects.

Environmental Matters

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

NOTE 7. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:

	Pension Benefits				Other Postretirement Benefits
	Three Months Ended March 31,
	Three Months Ended June 30,
(in millions)	2024		2023		2024		2023
Service Cost	$	43	$	3	$	1	$	1
Non-Service Cost (1)
Interest Cost	6		56		1		1
Expected Return on Plan Assets	(8)		(7)		~~(1)~~—		—(1)
Amortization of Net Loss	12		1		—		—
Net Periodic Benefit Cost	$	3	$	23	$	12	$	21


	Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Service Cost	$	7	$	6	$	2	$	2
Non-Service Cost (1)
Interest Cost	12		11		2		2
Expected Return on Plan Assets	(16)		(14)		(1)		(1)
Amortization of Net Loss	3		2		—		—
Net Periodic Benefit Cost	$	6	$	5	$	3	$	3

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

NOTE 8. 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.

1314

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

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

	Level 1		Level 2		Total
(in millions)	~~March~~June 3130, 2024
Assets
Cash Equivalents (1)	$	8	$	—	$	8
Restricted Cash (1)	$	29	$	—	$	29
Restricted Cash (1)	32		—		32
Energy Derivative Contracts, Regulatory Recovery (2)	—		33		33
Energy Derivative Contracts, Regulatory Recovery (2)	—		32		32
Energy Derivative Contracts, No Regulatory Recovery (2)	—		28		28
Energy Derivative Contracts, No Regulatory Recovery (2)	—		29		29
Total Assets	29		61		90
Total Assets	40		61		101
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(4741)		(4741)
Total Liabilities	—		(4741)		(4741)
Total Assets (Liabilities), Net	$	4029	$	1420	$	5449


(in millions)	December 31, 2023
Assets

Restricted Cash (1)	$	34	$	—	$	34
Energy Derivative Contracts, Regulatory Recovery (2)	—		32		32
Energy Derivative Contracts, No Regulatory Recovery (2)	—		3		3
Total Assets	34		35		69
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(30)		(30)


Total Liabilities	—		(30)		(30)
Total Assets (Liabilities), Net	$	34	$	5	$	39

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

(2)Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in 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)	~~March~~June 3130, 2024
Derivative Assets
Energy Derivative Contracts	$	61	$	21	$	—	$	40
Derivative Liabilities
Energy Derivative Contracts	(4741)		(21)		—		(2620)


(in millions)	December 31, 2023
Derivative Assets
Energy Derivative Contracts	$	35	$	15	$	—	$	20
Derivative Liabilities
Energy Derivative Contracts	(30)		(15)		—		(15)

DERIVATIVE INSTRUMENTS

TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers.

TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.

For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and 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~~16

	Three Months Ended March 31,
(in millions)		2024		2023
Unrealized Net Gain (Loss) (1)		$	(14)	$	(42)

(1)For the three months ended March 31, 2024 and 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Energy Derivative Contracts, Regulatory Recovery

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Unrealized Net Gain (Loss) (1)	$	6	$	(5)	$	(8)	$	(47)

(1)For the three months ended June 30, 2024, unrealized net gain on regulatory recoverable derivative contracts was primarily due to the settlement of gas contracts. For the six months ended June 30, 2024, unrealized net loss on regulatory recoverable derivative contracts was primarily due to changes in forward prices of power. For the three and six months ended June 30, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases 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 March 31,
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Operating Revenues	$	—	$	4	$	27	$	1317

Derivative Volumes

As of June 30, 2024, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

	March 31, 2024	December 31, 2023
	June 30, 2024	December 31, 2023
Power Contracts GWh	54,~~468~~221	1,449
Gas Contracts BBtu	9793,~~012~~048	89,105

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.

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 fair 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 $3133 million as of ~~March~~June 3130, 2024, compared with $28 million as of December 31, 2023. TEP had no cash posted as collateral to provide credit enhancement as of ~~March~~June 3130, 2024, and December 31, 2023. TEP would have been required to post $3133 million and $28 million of collateral if the credit risk contingent features had been triggered on March 31, 2024, and December 31, 2023, respectively. TEP had $7 million and $13 million in outstanding net payable balances for settled positions as of March 31, 2024, and December 31, 2023, respectively.

~~FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE~~17

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		March 31, 2024		December 31, 2023		March 31, 2024		December 31, 2023
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,397	$	2,397	$	2,085	$	2,127

contingent features had been triggered on June 30, 2024, and December 31, 2023, respectively. TEP had $14 million and $13 million in outstanding net payable balances for settled positions as of June 30, 2024, and December 31, 2023, respectively.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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


	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,398	$	2,397	$	2,054	$	2,127

NOTE 9. SUPPLEMENTAL CASH FLOW INFORMATION

CASH TRANSACTIONS


	Six Months Ended June 30,
(in millions)	2024		2023
Interest Paid, Net of Amounts Capitalized	$	42	$	39

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:

	Three Months Ended March 31,
	Six Months Ended June 30,
(in millions)	2024		2023
Accrued Capital Expenditures	$	4732	$	4731
Renewable Energy Credits	5		6
Net Cost of Removal Increase (Decrease) (1)	4		(3)
Asset Retirement Obligations Increase (Decrease)	(1)		(1)
Net Cost of Removal Increase (Decrease) (1)	(3)		(9)

(1)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings.

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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 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 Notes 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 2023 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," "our," and "us" 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 to a less carbon-intensive energy portfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. In ~~November~~ 2023, we announced our ~~new~~ aspirational goal of net zero direct GHG emissions by 2050. The ~~new~~ goal keeps us on pace to reduce carbon emissions by 80% compared to 2005 by 2035. The establishment of this additional target reinforces our commitment 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, and other external factors, including new customer growth.

•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 ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with the ~~first~~second ~~three~~quarter ~~months~~ of 2023

We reported net income of $5170 million in the ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with net income of $4748 million in the ~~first~~second ~~three~~quarter ~~months~~ of 2023. The increase of $422 million, or 946%, was primarily due to (net of tax):

•$1128 million in higher margin from retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order; ~~partially~~and ~~offset~~higher ~~by lower~~ usage as a result of ~~less~~ favorable weather; and ~~lower LFCR revenues;~~

•$7 2 million in higher ~~margin~~AFUDC ~~from wholesale transactions primarily~~ due to an increase in ~~revenues~~eligible ~~realized~~construction from wholesale trading as defined in the PPFAC plan of administration; partially offset by a decrease in long-term wholesale volumes due to less favorable market conditions and the expiration of certain contracts; andexpenditures.

~~•$3 million in higher AFUDC due to an increase in eligible construction expenditures.~~19

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The increase was partially offset by:

•$6 million in higher depreciation expense primarily due to an increase in depreciation rates as approved in the 2023 Rate Order; and

•$43 million in lower ~~margin~~interest ~~from~~income ~~transmission revenue~~ primarily due to a ~~regulatory~~reduction ~~decision~~in ~~approving~~under-recovered aPPFAC ~~credit to retail customers for certain transmission revenues;~~ costs.

~~•$3 million~~Performance in- ~~higher~~The ~~base~~first ~~operations~~six ~~and~~months ~~maintenance~~of ~~expenses~~2024 ~~primarily~~compared ~~due~~with tothe anfirst ~~increase~~six inmonths ~~outside~~of ~~service~~2023 ~~expenses and higher maintenance costs at our generation facilities; and~~

•We reported net income of $1 122 million in ~~lower~~the ~~interest~~first ~~income~~six ~~due~~months toof a2024 ~~reduction~~compared with net income of $95 million in ~~under-recovered~~the ~~PPFAC~~first ~~costs~~six months of 2023. The increase of $27 million, or 28%, was primarily due to (net of tax):

•$39 million in higher margin from retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order and higher usage as a result of favorable weather; partially offset by lower LFCR revenues;

•$6 million in higher margin from wholesale transactions primarily due to an increase in revenues realized from wholesale trading as defined in the PPFAC plan of administration; partially offset by a decrease in long-term wholesale volumes due to less favorable market conditions and the expiration of certain contracts; and

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

The increase was partially offset by:

•$12 million in higher depreciation expense primarily due an increase in depreciation rates as approved in the 2023 Rate Order;

•$4 million in lower interest income primarily due to a reduction in under-recovered PPFAC costs;

•$3 million in higher base operations and maintenance expenses primarily due to an increase in employee wages and benefits expenses and an increase in outside services expenses; partially offset by lower operations and maintenance expenses at our generation facilities; and

•$2 million in lower margin from transmission revenue primarily due to a regulatory decision approving a credit to retail customers for certain transmission revenue; partially offset by an increase in TEP's transmission formula rate revenue requirement.

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~~sales ~~patterns~~growth and seasonality.

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;

•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%; and

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

Generation Resource Strategy

Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while reducing reliance on coal-fired generation resources. In ~~November~~ 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards a new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps us on pace to reduce our carbon emissions by 80% compared to 2005 by 2035.

As a result of our 2022 All-Source Request for Proposal (ASRFP), we entered into an EPC agreement to develop Roadrunner Reserve I and a renewable PPA with Wilmot Energy Center II (Wilmot II). Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage with an anticipated in service date in 2026. In December 2023, we issued another ASRFP based on the resource needs outlined in our 2023 IRP, including natural gas-fired generation, targeting in-service dates of 2026 through 2027. 20

In April 2024, as a result of our 2022 ASRFP, we entered into a PPA with Winchester Solar I, LLC (Winchester). Winchester will have 80 MW of solar capacity accompanied by 80 MW of battery storage with an anticipated in service date of March 2027.

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 expect to exit all ownership interests in coal-fired generation facilities by 2032. We will seek regulatory recovery for amounts, if any, that would not otherwise be recovered as a result of these actions. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings.

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growth and maintain affordable, reliable service as we work towards a new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps us on pace to reduce our carbon emissions by 80% compared to 2005 by 2035.

As a result of our 2022 All-Source Request for Proposal (ASRFP), we entered into:

•an EPC agreement in September 2023 to develop Roadrunner Reserve I. Roadrunner Reserve I will be a standalone BESS facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh with an anticipated in-service date in 2025;

•a renewable PPA in January 2024 with Wilmot Energy Center II (Wilmot II). Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage with an anticipated in-service date in 2026; and

•a renewable PPA in April 2024 with Winchester Solar I, LLC (Winchester). Winchester will have 80 MW of solar capacity accompanied by 80 MW of battery storage with an anticipated in-service date in 2027.

In December 2023, we issued another ASRFP based on the resource needs outlined in our 2023 IRP, including natural gas-fired generation, targeting in-service dates of 2026 through 2027.

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 ~~PTCs~~approximately of$6 ~~approximately~~million and $4 10 million in ~~each~~PTCs ofrelated to Oso Grande for the three and six months ended ~~March~~June 3130, 2024, respectively, and $4 million and $9 million, for the three and six months ended June 30, 2023, respectively. The PTC rate published by the IRS for electricity produced by a qualified facility using wind placed in service prior to 2022 is $0.029 for 2024 and was $0.028 for 2023.

Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, or if any operational constraints exist, the project's electricity generation and associated PTCs may be substantially different compared to prior periods. As of September 1, 2023, Oso Grande is included in rates as part of the 2023 Rate Order.

Sales Growth and Seasonality

Our average retail sales growth has remained relatively flat over the past three years. Recently, we have experienced unprecedented interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet above what is reflected in our 2023 IRP, as well as higher transmission and distribution infrastructure investments. We are analyzing the requests and cannot predict the quantity or timing of the energy demand that may result from the current interest received.

Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our retail sales are highest in the second and 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. Our operating costs are generally consistent throughout the year which produces higher operating income in the second and third quarter and lower operating income in the first and fourth quarter. As a result, seasonal fluctuations affect the comparability of our results of operations.

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Interest Rates

See Part II, Item 7A in our 2023 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 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~~SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.

The following discussion provides the significant items that affected our results of operations ~~for~~in the second quarter and first ~~three~~six months of 2024 compared with the same period in 2023 presented on a pre-tax basis.

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Operating Revenues

The following table provides a disaggregation of Operating Revenues:

	Three Months Ended March 31,				Increase (Decrease)
	Three Months Ended June 30,				Increase (Decrease)		Six Months Ended June 30,				Increase (Decrease)
(in millions)	2024		2023		Percent		2024		2023		Percent
Operating Revenues
Retail	$	~~282~~334	$	~~233~~297	2112.05	%	$	616	$	530	16.2	%
Wholesale, Short-Term (1)	8427		9442		(1035.67)	%	111		136		(18.4)	%
Wholesale, Long-Term	1912		2913		(347.57)	%	31		42		(26.2)	%
Transmission	1413		1712		~~(17~~8.6)3	%	26		29		(10.3)	%
Springerville Units 3 and 4 Participant Billings	3623		2736		33(36.31)	%	59		63		(6.3)	%
Other	1821		3618		~~(50~~16.0)7	%	39		54		(27.8)	%
Total Operating Revenues	$	~~453~~430	$	~~436~~418	32.9	%	$	882	$	854	3.3	%

(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 $453 million for the first three months of 2024 compared with $436 million in the same period for 2023. The increase of $17 million, or 4%, was primarily due to:~~ 22

•$49 million in higher retail revenue primarily due to: (i) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate; and (ii) an increase in rates as approved in the 2023 Rate Order; partially offset by lower usage as a result of less favorable weather; and

•$9 million in higher participant billings primarily related to Springerville Unit 4.

The increase was partially offset by:

•$18 million in lower other revenue primarily due to the expiration of an asset management agreement and lower LFCR revenues;

•$10 million in lower short-term wholesale sales primarily due to a decrease in price; partially offset by an increase in volume and an increase in revenue realized from wholesale trading as defined in the PPFAC plan of administration; and

•$10 million in lower long-term wholesale sales primarily due to a decrease in volumes due to less favorable market conditions and the expiration of certain contracts.

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	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2024	2023	Percent
Electric Sales (kWh) (1)
Retail Sales	1,795	1,822	(1.5)	%
Wholesale, Long-Term	317	474	(33.1)	%
Wholesale, Short-Term	1,533	941	62.9	%
Total Electric Sales	3,645	3,237	12.6	%
Average Revenue per kWh (2)
Retail	15.71	12.78	22.9	%
Wholesale, Long-Term	5.85	6.07	(3.6)	%
Wholesale, Short-Term	3.73	8.61	(56.7)	%
Total Retail Customers (3)	449,619	444,834	1.1	%

We reported Operating Revenues of $430 million in the second quarter of 2024 compared with $418 million in the same period for 2023. The increase of $12 million, or 3%, was primarily due to $37 million in higher retail revenue primarily due to: (i) an increase in rates as approved in the 2023 Rate Order; (ii) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate; and (iii) higher usage as a result of favorable weather.

The increase was partially offset by:

•$15 million in lower short-term wholesale revenues primarily due to a decrease in price; and

•$13 million in lower Springerville Units 3 and 4 participant billings primarily due to higher reimbursable planned outage costs in 2023.

We reported Operating Revenues of $882 million for the first six months of 2024 compared with $854 million in the same period for 2023. The increase of $28 million, or 3%, was primarily due to $86 million in higher retail revenues primarily due to: (i) an increase in rates as approved in the 2023 Rate Order; (ii) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate; and (iii) higher usage as a result of favorable weather.

The increase was partially offset by:

•$25 million in lower short-term wholesale revenues primarily due to a decrease in price; partially offset by an increase in revenue realized from wholesale trading as defined in the PPFAC plan of administration;

•$15 million in lower other revenue primarily due to the expiration of an asset management agreement and lower alternative revenues;

•$11 million in lower long-term wholesale revenues primarily due to a decrease in volumes due to less favorable market conditions and the expiration of certain contracts;

•$4 million in lower Springerville Units 3 and 4 participant billings primarily due to higher reimbursable planned outage costs in 2023; and

•$3 million in lower transmission revenues primarily due to a regulatory decision in December 2023 approving a credit to retail customers for certain transmission revenue; partially offset by an increase in TEP's transmission formula rate revenue requirement.

The following table provides key statistics impacting Operating Revenues:


	Three Months Ended June 30,		Increase (Decrease)		Six Months Ended June 30,		Increase (Decrease)
(kWh in millions)	2024	2023	Percent		2024	2023	Percent
Electric Sales (kWh) (1)
Retail Sales	2,230	2,162	3.1	%	4,025	3,984	1.0	%
Wholesale, Long-Term	197	257	(23.3)	%	514	731	(29.7)	%
Wholesale, Short-Term	1,245	1,100	13.2	%	2,778	2,041	36.1	%
Total Electric Sales	3,672	3,519	4.3	%	7,317	6,756	8.3	%

Average Revenue per kWh (2)
Retail	14.96	13.75	8.8	%	15.30	13.31	15.0	%
Wholesale, Long-Term	6.17	4.96	24.4	%	5.97	5.68	5.1	%
Wholesale, Short-Term	2.11	3.49	(39.5)	%	3.01	5.85	(48.5)	%

Total Retail Customers (3)					450,126	445,343	1.1	%

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

(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.

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

Operating Expenses

Fuel and Purchased Power Expense

We reported Fuel and Purchased Power expense of $~~179~~145 million ~~for~~in the ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with $~~185~~154 million ~~for~~in the same period for 2023. The decrease of $69 million, or 36%, was primarily due to: $20 million in lower Purchased Power expenses primarily due to a decrease in price and volume. The decrease was partially offset by a $12 million increase in PPFAC Recovery Treatment primarily due to an increase in PPFAC cost recoveries and a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery.

~~•$23~~We ~~million~~reported inFuel ~~lower~~and ~~Fuel~~Purchased Power expense ~~due~~of to$323 million afor ~~decrease~~the infirst ~~natural~~six ~~gas~~months ~~prices;~~of ~~partially~~2024 ~~offset~~compared bywith an$339 million ~~increase~~for inthe ~~coal~~same ~~prices~~period ~~and~~for an2023. ~~increase~~The indecrease ~~Gas-Fired~~of ~~Generation~~$16 million, ~~volumes;~~or ~~and~~5%, was primarily due to:

•$1030 million in lower Purchased Power ~~expense~~expenses primarily due to a decrease in price. and volume; and

~~The~~•$24 million in lower Fuel expense primarily due to a decrease ~~was~~in natural gas prices; partially offset by: a(i) ~~$25~~an ~~million~~ increase in ~~PPFAC~~coal ~~Recovery~~prices; ~~Treatment~~(ii) ~~primarily~~higher ~~due~~realized tolosses on natural gas swaps; and (iii) an increase in ~~PPFAC~~Gas-Fired ~~cost~~Generation ~~recoveries~~volumes.

22The decrease was partially offset by a $37 million increase in PPFAC Recovery Treatment primarily due to an increase in PPFAC cost recoveries.

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

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	Three Months Ended June 30,		Increase (Decrease)		Six Months Ended June 30,		Increase (Decrease)
(kWh in millions)	2024	2023	Percent		2024	2023	Percent
Sources of Energy
Coal-Fired Generation	643	594	8.2	%	1,579	1,575	0.3	%
Gas-Fired Generation	2,098	1,833	14.5	%	3,990	3,415	16.8	%
Utility-Owned Renewable Generation	216	193	11.9	%	414	423	(2.1)	%
Total Generation	2,957	2,620	12.9	%	5,983	5,413	10.5	%
Purchased Power, Non-Renewable	450	611	(26.4)	%	853	790	8.0	%
Purchased Power, Renewable	403	419	(3.8)	%	721	774	(6.8)	%
Total Generation and Purchased Power (1)	3,810	3,650	4.4	%	7,557	6,977	8.3	%

	Three Months Ended March 31,		Increase (Decrease)
(cents per kWh)
(kWh in millions)	2024	2023	Percent
Average Fuel Cost of Generated Power (2)
Sources of Energy
Coal	3.53	3.21	10.0	%	4.66	3.02	54.3	%
Coal-Fired Generation	936	981	(4.6)	%
Natural Gas (3)	1.87	2.34	(20.1)	%	2.23	4.03	(44.7)	%
Gas-Fired Generation	1,892	1,582	19.6	%
Average Cost of Purchased Power (4)
Utility-Owned Renewable Generation	198	230	(13.9)	%
Purchased Power, Non-Renewable	0.87	4.27	(79.6)	%	1.10	5.39	(79.6)	%
Total Generation	3,026	2,793	8.3	%
Purchased Power, Renewable	7.11	6.93	2.6	%	6.95	6.71	3.6	%
Purchased Power, Non-Renewable	403	179	125.1	%
Purchased Power, Renewable	318	355	(10.4)	%
Total Generation and Purchased Power (1)	3,747	3,327	12.6	%

(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal	5.43	2.91	86.6	%
Natural Gas (3)	2.62	5.98	(56.2)	%
Average Cost of Purchased Power (4)
Purchased Power, Non-Renewable	1.36	9.20	(85.2)	%
Purchased Power, Renewable	6.75	6.45	4.7	%

(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.

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(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.

Operations and Maintenance Expense

We reported Operations and Maintenance expense of $~~119~~ 106 million ~~for~~in the ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with $~~108~~120 million ~~for~~in the same period for 2023. The ~~increase~~decrease of $1114 million, or 1012%, was primarily due to: lower reimbursable maintenance expense related to Springerville Units 3 and 4 primarily due to higher planned outage costs in 2023.

~~•$8~~We ~~million~~reported inOperations ~~higher~~and ~~reimbursable~~Maintenance ~~maintenance~~expense ~~expenses~~of ~~related~~$224 tomillion ~~Springerville~~for ~~Unit~~the 4first ~~primarily~~six ~~due~~months toof ~~planned~~2024 ~~outages;~~compared ~~partially~~with ~~offset~~$228 million byfor ~~lower~~the ~~reimbursable~~same ~~maintenance~~period ~~expenses~~for ~~related~~2023. toThe ~~Springerville~~decrease ~~Unit~~of 3;$4 million, ~~and~~or 2%, was primarily due to:

•$34 million in ~~higher~~lower ~~outside~~reimbursable ~~service~~maintenance ~~expenses~~expense ~~and~~related ~~operations~~to Springerville Units 3 and ~~maintenance~~4 ~~expenses~~primarily atdue ~~our~~to ~~generation~~higher ~~facilities.~~planned outage costs in 2023;

~~The increase was partially offset by~~ •$24 million in lower ~~RES~~operations and ~~DSM~~maintenance expenses. at our generation facilities; and

•$3 million in lower RES and DSM expenses.

The decrease was partially offset by:

•$4 million in higher employee wages and benefits expenses; and

•$3 million in higher outside services expenses.

Depreciation and Amortization Expense

We reported Depreciation and Amortization expense of $6364 million ~~for~~in the ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with $57 million ~~for~~in the same period for 2023. The increase of $67 million, or 1112%, was primarily due to an increase in depreciation rates as approved in the 2023 Rate Order.

We reported Depreciation and Amortization expense of $127 million for the first six months of 2024 compared with $114 million for the same period for 2023. The increase of $13 million, or 11%, was primarily due to an increase in depreciation rates as approved in the 2023 Rate Order.

Other Income (Expense)

We reported Other Expense of $1516 million ~~for~~in the ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with $16 million ~~for~~in the same period for 2023. ~~The~~There ~~decrease~~is no material change in the second quarter of ~~$1 million,~~2024 orcompared ~~6%,~~to ~~was~~the same period in 2023 primarily due to $4 million in lower interest income on under-recovered PPFAC balances; partially offset by $3 million in higher AFUDC due to an increase in eligible construction expenditures.

23We reported Other Expense of $31 million for the first six months of 2024 compared with $32 million for the same period for 2023. The decrease of $1 million, or 3%, was primarily due to $6 million in higher AFUDC due to an increase in eligible construction expenditures; partially offset by $5 million in lower interest income on under-recovered PPFAC balances.

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construction expenditures; partially offset by $1 million in lower interest income primarily due to a reduction in under-recovered PPFAC costs.

Income Tax Expense

We reported Income Tax Expense of $711 million ~~for~~in the ~~first~~second ~~three~~quarter ~~months~~ of 2024 compared with $67 million ~~for~~in the same period for 2023. The increase of $14 million, or 1757%, was primarily due to $7 million in higher tax expense due to an increase in taxable earnings; the increase was partially offset by $2 million in higher tax credits related to Oso Grande PTCs.

We reported Income Tax Expense of $18 million for the first six months of 2024 compared with $13 million for the same period for 2023. The increase of $5 million, or 38%, was primarily due to $8 million in higher tax expense due to an increase in taxable earnings; the increase was partially offset by $1 million in higher tax credits related to Oso Grande PTCs.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Any extended period of economic disruption could affect our business, financial condition, 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. We face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to 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)	~~March~~June 3130, 2024
Cash and Cash Equivalents	$	5715
Amount Available under Revolving Credit Agreement (1)	250
Total Liquidity	$	~~307~~265

(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.

Summary of Cash Flows

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

	Three Months Ended March 31,				Increase (Decrease)
	Six Months Ended June 30,				Increase (Decrease)
(in millions)	2024		2023		Percent
Operating Activities	$	~~190~~296	$	~~121~~215	5737.07	%
Investing Activities	(~~144~~296)		(~~129~~260)		1113.68	%
Financing Activities	—1		~~135~~79		(~~100~~98.07)	%
Net Increase (Decrease)	461		~~127~~34		(6397.81)	%
Beginning of Period	43		51		(15.7)	%
End of Period	$	8944	$	~~178~~85	(5048.02)	%

Operating Activities

Net cash flows provided by operating activities increased by $6981 million in the first ~~three~~six months of 2024 compared with the same period in 2023. The increase was primarily due to: (i) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate; and (ii) higher retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order and favorable weather.

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PPFAC rate; (ii) higher retail revenues related to an increase in rates as approved in the 2023 Rate Order; and (iii) favorable changes in working capital associated with wholesale sales.

Investing Activities

Net cash flows used for investing activities increased by $1536 million in the first ~~three~~six months of 2024 compared with the same period in 2023 primarily due to an increase in cash paid for capital expenditures.

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Financing Activities

Net cash flows provided by financing activities decreased by $~~135~~ 78 million in the first ~~three~~six months of 2024 compared with the same period in 2023 primarily due to a decrease in proceeds from long-term debt, net of repayments; partially offset by a decrease in dividends declared and paid to UNS Energy.

Sources of Liquidity

Short-Term Investments

Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of ~~March~~June 3130, 2024, ~~our~~we had no 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 will be issued from time to time to support energy procurement, hedging transactions, and other business activities.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2023 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 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. In May 2022, we filed with the SEC an automatic shelf registration statement on Form S-3 which expires in May 2025.

We have, from time to time, refinanced or repurchased portions of our outstanding debt before scheduled maturity. Depending on market conditions, we may refinance or repurchase additional outstanding debt before its scheduled maturity.

As of ~~March~~June 3130, 2024, we had $300 million of long-term debt maturing on March 15, 2025 recorded in Current Maturities of Long-Term Debt, Net on the Condensed Consolidated Balance Sheets. We anticipate issuing long-term debt in the third quarter of 2024.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of ~~March~~June 3130, 2024, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- (negative) and A3 (stable), 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.

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Debt Covenants

Under certain agreements, should we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of ~~March~~June 3130, 2024, 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.

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Contributions from Parent

We received no equity contributions from UNS Energy in the second quarter or first ~~three~~six months of 2024. We received no equity contributions from UNS Energy in the second quarter of 2023 and received an equity contribution of $6 million in the first ~~three~~six months of 2023.

Dividends Declared and Paid to Parent

We did not declare or pay dividends to UNS Energy in the second quarter or first ~~three~~six months of 2024. orWe declared and paid $55 million in dividends to UNS Energy in the second quarter and first six months of 2023. On July 25, 2024, we declared a dividend of up to $85 million to be paid to UNS Energy on or before December 31, 2024.

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 for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of ~~March~~June 3130, 2024, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.

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. In the first ~~three~~six months of 2024, there were no material changes to our forecasted capital expenditures as reported in our 2023 Annual Report on Form 10-K.

Income Tax Position

Under the terms of the tax sharing agreement with UNS Energy, we made $35 million in tax sharing payments for the first ~~three~~six months of 2024 and received $6 4 million in tax sharing payments for the first ~~three~~six months of 2023. Future ~~cash~~tax ~~flows~~payments or receipts are subject to change and are not expected to have a significant impact on our operating cash flows.

Environmental Matters

The ~~Environmental Protection Agency (~~EPA) has the authority to regulate the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. 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 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 the ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls ~~evaluation~~evaluations. We conducted the potential emissions controls evaluations, 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.

WeIn ~~conducted~~May 2024, the ~~potential~~EPA ~~emissions~~published ~~controls~~a ~~evaluation,~~proposed ~~commonly~~rule ~~referred~~ to aspartially ~~the~~approve ~~four~~and ~~factor~~partially ~~analysis,~~disapprove ~~for~~ the ~~three~~ADEQ’s ~~units.~~Regional ~~These~~Haze ~~evaluations~~SIP ~~were~~revision. ~~submitted~~The EPA proposed to ~~the~~disapprove ADEQ’s control strategy in ~~March~~the ~~2020~~revised ~~and~~SIP, which relies, in part, on the compliance measures for ~~the~~Sundt ~~three~~Unit ~~units~~3 ~~were~~and ~~included~~Springerville inUnits ~~the~~1 ~~revised~~and ~~SIP~~2. The EPA also requested further evaluation of Sundt Unit 4. In ~~August~~the ~~2022~~event that the EPA finalizes the rule as proposed, the ADEQ ~~submitted~~has the ~~revised~~opportunity ~~SIP~~to respond to the EPA, and cure the deficiencies. In the alternative, the EPA ~~issued~~will issue a ~~letter~~federal toimplementation ~~the~~plan ~~ADEQ~~(FIP) that may contain EPA-required

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~~finding~~compliance ~~Arizona's~~measures ~~SIP~~for ~~revision~~these ~~complies~~units ~~with~~at ~~the~~Sundt ~~completeness~~and ~~criteria outlined in the rule~~Springerville. The EPA must take final action on Arizona's Regional Haze SIP Revision by March 30, 2025, per consent decree entered in the U.S. District Court for the District of Columbia. 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.

The public comment period for the proposal closed on July 15, 2024. We cannot predict the outcome of this matter.

Greenhouse Gas Regulation

InOn ~~August~~May ~~2015~~9, 2024, the EPA ~~issued~~published ~~the~~final ~~Clean~~rules ~~Power~~to ~~Plan~~regulate GHG emissions from two categories of fossil-based electric generating units (~~CPP~~EGUs): ~~limiting~~(i) ~~CO2~~existing ~~emissions~~steam ~~from~~units ~~existing~~(including coal- and natural gas-fired); and (ii) new ~~fossil~~natural ~~fuel-based~~gas ~~generation~~fired ~~facilities~~turbines. The ~~CPP~~EPA ~~established~~did ~~state-level~~not ~~CO2~~take ~~emission~~final ~~rates~~action ~~and~~on ~~mass~~existing natural gas-~~based~~fired ~~goals~~combustion turbines but has indicated that ~~applied~~it plans to ~~fossil~~issue ~~fuel-based~~a ~~generation~~supplemental proposal to address these units by the end of 2024.

InThe ~~June~~final ~~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.established:

In•Emission ~~January~~guidelines ~~2021, the U.S. Court of Appeals~~ for ~~the~~existing ~~D.C.~~coal-fired ~~Circuit:~~steam (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 petitionersEGUs, ~~defending~~which ~~the~~are ~~repeal~~subcategorized ofbased ~~the~~on ~~CPP,~~federally ~~filed~~enforceable ~~petitions~~retirement ~~for an order requesting that the U~~dates.S. ~~Supreme~~These ~~Court~~emission ~~review~~guidelines ~~the~~affect ~~decision~~Springerville ofUnits ~~the~~1 ~~lower~~and ~~court. The U.S. Supreme Court granted the petitions~~2, ~~consolidated~~as ~~the~~well ~~cases,~~as ~~and~~Four inCorners ~~June~~Units ~~2022,~~4 ~~reversed the D.C. Circuit~~ and ~~remanded the cases back for further proceedings.~~ 5;

On•Emission ~~April~~guidelines ~~25,~~for ~~2024,~~existing ~~the~~natural ~~EPA~~gas- ~~released~~and aoil-fired ~~final~~steam ~~rule~~EGUs ~~repealing~~aligned ~~the~~with ~~ACE~~routine ~~rule~~methods ~~and~~of ~~addressing~~operation ~~GHG~~and ~~emissions~~maintenance, ~~from~~which ~~existing~~are ~~steam~~subcategorized ~~electric~~based ~~generating~~on ~~units~~the ~~and~~annual ~~new~~capacity ~~combustion~~factor ~~turbines.~~of Weeach ~~are~~unit ~~analyzing~~beginning ~~the~~January ~~EPA's~~1, ~~final~~2030. ~~rule~~These ~~and~~emission ~~cannot~~guidelines ~~predict~~affect ~~the~~Sundt ~~outcome~~Units of3 ~~this~~and ~~matter at this time~~4.

•A requirement for states to establish standards of performance that align with the emission guidelines, in the form of emission limits. States must submit these standards of performance to the EPA for approval in the form of a state plan, which is due to the EPA in May 2026; and

•New source performance standards for new stationary natural gas-fired combustion turbines, which are subcategorized based on the annual capacity factor for each unit. For base load units (i.e., units with an annual capacity factor greater than 40%), the EPA established a two-phased performance standard. For phase 1, new base load units must initially meet performance standards based on the use of highly efficient combined cycle generation with the best operating and maintenance practices. For phase 2, the final rule requires that such base load units achieve emissions reductions aligned with a 90% carbon capture and sequestration (CCS) rate beginning on January 1, 2032.

We are analyzing the EPA's final rule. Various legal challenges to the final rule are pending before the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this matter.

Coal Combustion Residuals Regulation

In April 2015, the EPA published final rules effective October 2015 (2015 CCR Rule), which established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The 2015 CCR ~~rules~~Rule ~~provide~~provides for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at ~~the~~ Springerville ~~Generating Station~~. Arizona Public Service Company, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility. AtSRP, ~~this~~the ~~time,~~former weoperator doof ~~not~~Navajo, ~~anticipate~~is ~~our~~completing ~~share~~closure ofactivities at the ~~cost~~facility's toCCR ~~complete~~landfill. ~~any~~With regards to future corrective actions at Four Corners to ~~close~~comply with the 2015 CCR ~~disposal~~Rule, ~~units~~our share of costs to complete any corrective actions, or to gather and perform remedial evaluations on groundwater at ~~Four Corners~~ Units 4 and 5, ~~will~~is not expected to have a significant impact on our financial position, results of operations, or cash flows.

InOn May ~~2023~~8, 2024, the EPA published athe ~~proposed~~final Legacy CCR Surface Impoundments Rule that expands the scope of ~~federal~~the 2015 CCR ~~regulations~~Rule to address the impacts from historical CCR ~~disposal~~management and placement activities that would have ceased prior to 2015. The EPA ~~proposes~~rule toestablishes ~~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~~Management ~~units~~Units (CCRMUs) which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. AsA ~~proposed,~~CCRMU aincludes ~~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. OnThe ~~April 25, 2024, the EPA released the~~ final rule ~~which~~also establishes assessment, groundwater monitoring, closure, and post-closure requirements for legacy CCR impoundments and ~~CCR management units~~CCRMUs. ~~We are analyzing the EPA's final rule and cannot predict the outcome of this matter at this time.~~

We are analyzing the EPA's final rule for potential impacts to our operations. We anticipate that CCRMUs will be identified at Springerville and Four Corners. The number, location, and size of these CCRMUs are being assessed; therefore, associated compliance costs cannot be accurately predicted at this time. SRP identified CCRMUs at Navajo. Our estimated cost to comply with the EPA's final rule at Navajo is not expected to have a significant impact on our financial position, results of operations, or cash flows.

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Good Neighbor Federal Implementation Plan

In September 2018, the ADEQ submitted to the EPA the Arizona State Implementation Plan Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone National Ambient Air Quality Standard (NAAQS). In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.

In March 2023, the EPA released its final ~~Federal Implementation Plan (~~FIP) to address the interstate transport of ozone (Good Neighbor FIP). The Good Neighbor FIP was published in the Federal Register in June 2023, with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.

27In February 2024, the EPA published a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona’s inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOx emission reduction requirements. The EPA must take final action on Arizona’s Ozone Transport SIP Revision by August 30, 2024, per consent decree entered in the U.S. District Court for the Northern District of California.

~~Table~~On June 27, 2024, the U.S. Supreme Court granted a stay of ~~Contents~~the Good Neighbor FIP pending the disposition of the petitions for review of the Good Neighbor FIP currently pending in the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this matter.

Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.

In February 2024, the EPA published a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona’s inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOx emission reduction requirements. The EPA must take final action on Arizona’s Ozone Transport SIP Revision by August 30, 2024, per consent decree entered in the U.S. District Court for the Northern District of California. The public comment period is currently open and closes May 16, 2024.

TEP is analyzing the EPA’s proposal. We cannot predict the outcome of these matters at this time but will continue to advocate for reasonable regulation and maintain communication with the ADEQ.

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 ~~three~~six months ended ~~March~~June 3130, 2024, 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 2023 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. TEP 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 2023 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 March 31, 2024. There was no change in TEP’s internal control over financial reporting during

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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 June 30, 2024. There was no change in TEP’s internal control over financial reporting during the quarter ended ~~March~~June 3130, 2024, 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 6 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 2023 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 2023 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 ~~March~~June 3130, 2024, 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:	~~April~~July 30, 2024	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President, Chief Financial Officer, and Director
		(Principal Financial Officer)

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