tep-20230630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2023

☐ 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 August 1, 2023.

Table of Contents


Definitions			iii
Forward-Looking Information			v
PART I

Item 1. Financial Statements
Condensed Consolidated Statements of Income			1

Condensed Consolidated Statements of Cash Flows			2
Condensed Consolidated Balance Sheets			3
Condensed Consolidated Statements of Changes in Stockholder's Equity			5
Notes to Condensed Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
Critical Accounting Estimates			31
New Accounting Standards Issued and Not Yet Adopted			31
Item 3. Quantitative and Qualitative Disclosures about Market Risk			32
Item 4. Controls and Procedures			32

PART II

Item 1. Legal Proceedings			33
Item 1A. Risk Factors			33

Item 6. Exhibits			34
Signatures			35

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS



2022 Final FERC Rate Order						The order issued by the FERC in 2022 approving the settlement agreement filed in conjunction with TEP's 2019 transmission rate case

2020 IRP						TEP's 2020 Integrated Resource Plan, which calls for TEP to reduce its carbon emissions by 80% and to supply more than 70% of its energy to retail customers from renewable resources 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
2022 Rate Case						TEP's general rate case filed with the ACC in 2022 based on a test year ended December 31, 2021

ACC						Arizona Corporation Commission


AFUDC						Allowance for Funds Used During Construction
ALJ						Administrative Law Judge
AMT						Alternative Minimum Tax
BTA						Build-Transfer Agreement
CARES Act						Coronavirus Aid, Relief, and Economic Security Act
COVID-19						Coronavirus Disease 2019
DG						Distributed Generation
DSM						Demand Side Management





FERC						Federal Energy Regulatory Commission
GAAP						Generally Accepted Accounting Principles in the United States of America
GHG						Greenhouse Gas
IRA						Inflation Reduction Act, signed into law on August 16, 2022

LFCR						Lost Fixed Cost Recovery

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

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

ENTITIES AND GENERATING STATIONS



Fortis						Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners						Four Corners Generating Station



Oso Grande						A wind-powered electric generation facility, located in southeastern New Mexico
San Juan						San Juan Generating Station

Springerville						Springerville Generating Station

Sundt						H. Wilson Sundt Generating Station
TEP						Tucson Electric Power Company, the principal subsidiary of UNS Energy

UNS Electric						UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy

iii


UNS Energy						UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates						Affiliated subsidiaries of UNS Energy including UniSource Energy Services, Inc., UNS Electric, and UNS Gas
UNS Gas						UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy

UNITS OF MEASURE


BBtu						Billion British thermal unit(s), a measure of the quantity of heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit at the temperature at which water has its greatest density, in billions
GWh						Gigawatt-hour(s), a measure of electricity that represents one billion watts of power expended over one hour
kWh						Kilowatt-hour(s), a measure of electricity that represents one thousand watts of power expended over one hour
MW						Megawatt(s), a measure of electricity that represents one million watts of power
MWh						Megawatt-hour(s), a measure of electricity that represents one million watts of power expended over one hour

Table of Contents

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. TEP, or the Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany such forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as may otherwise be required by the federal securities laws.

Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed therein. We express our estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part I, Item 1A. Risk Factors of our 2022 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Form 10-Q; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax, inclusive of the IRA and evolving interpretive guidance related thereto, and energy policies and the adoption of new regulations regarding electric service disconnections; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies; and/or changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output, or accelerate generation facility retirements; the outcome of the 2022 Rate Case and any additional phase thereof; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; the continuation of 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, affecting electricity usage of our customers and the performance of our operations; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the expected demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital and use the proceeds from any capital that we do raise as originally intended; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and related contribution requirements and expenses; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense, including increases due to inflationary effects; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting estimates; the ongoing impact of mandated energy efficiency and DG initiatives; our ability to effectively implement plans to meet our goals related to reducing carbon emissions by 2035, and the potential impact on our financial condition; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other cyberspace attacks to our information security and our operations and technology infrastructure, including attacks that may rise from heightened geopolitical instability; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; the extent of the impact of a global health 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 ongoing implementation of our 2020 IRP.

Table of Contents

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Operating Revenues	$	418,236	$	439,527	$	854,089	$	776,253

Operating Expenses
Fuel	64,630		105,809		188,700		188,773
Purchased Power	47,136		53,487		83,576		84,031
Transmission and Other PPFAC Recoverable Costs	15,362		20,911		31,961		37,746
Increase (Decrease) to Reflect PPFAC Recovery Treatment	26,583		(2,365)		34,497		(14,246)
Total Fuel and Purchased Power	153,711		177,842		338,734		296,304
Operations and Maintenance	119,983		101,337		228,042		198,570
Depreciation	47,424		54,450		94,564		108,048
Amortization	9,803		9,939		19,494		19,857
Taxes Other Than Income Taxes	17,103		15,266		34,380		31,965
Total Operating Expenses	348,024		358,834		715,214		654,744

Operating Income	70,212		80,693		138,875		121,509

Other Income (Expense)
Interest Expense	(24,172)		(21,144)		(47,488)		(42,634)
Allowance For Borrowed Funds	1,161		803		2,169		1,413
Allowance For Equity Funds	3,249		2,370		6,142		4,041
Unrealized Gains (Losses) on Investments	433		(3,937)		1,793		(6,721)
Other, Net	3,666		3,436		5,757		6,422
Total Other Income (Expense)	(15,663)		(18,472)		(31,627)		(37,479)

Income Before Income Tax Expense	54,549		62,221		107,248		84,030
Income Tax Expense	6,823		7,247		12,629		9,636
Net Income	$	47,726	$	54,974	$	94,619	$	74,394

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)


	Six Months Ended June 30,
	2023		2022
Cash Flows from Operating Activities
Net Income	$	94,619	$	74,394
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	94,564		108,048
Amortization Expense	19,494		19,857

Amortization of Debt Issuance Costs	1,541		1,480
Use of Renewable Energy Credits for Compliance	22,608		23,237
Deferred Income Taxes	9,915		8,219

Pension and Other Postretirement Benefits Expense	7,588		5,824
Pension and Other Postretirement Benefits Funding	(4,727)		(6,027)

Allowance for Equity Funds Used During Construction	(6,142)		(4,041)




Changes in Current Assets and Current Liabilities:
Accounts Receivable	108,638		(63,817)
Materials, Supplies, and Fuel Inventory	(18,147)		11,183
Regulatory Assets	22,679		(33,048)

Other Current Assets	859		236
Accounts Payable and Accrued Charges	(118,955)		85,946

Income Taxes Receivable/Payable	(1,086)		(51)
Regulatory Liabilities	(3,219)		1,066
Other, Net	(14,877)		26,564
Net Cash Flows—Operating Activities	215,352		259,070
Cash Flows from Investing Activities
Capital Expenditures	(231,472)		(211,663)



Purchase Intangibles, Renewable Energy Credits	(31,718)		(33,892)


Contributions in Aid of Construction	2,539		4,804

Net Cash Flows—Investing Activities	(260,651)		(240,751)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	—		5,000
Repayments of Borrowings, Revolving Credit Facility	—		(20,000)


Proceeds from Issuance, Long-Term Debt—Net of Discount	373,954		323,804
Repayments of Long-Term Debt	(240,745)		(193,465)
Dividend Paid to Parent	(55,000)		—

Payment of Debt Issuance Costs	(4,092)		(2,931)
Contribution from Parent	5,900		—

Other, Net	(877)		3,764
Net Cash Flows—Financing Activities	79,140		116,172
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	33,841		134,491
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	50,981		33,489
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	84,822	$	167,980

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	June 30, 2023		December 31, 2022
ASSETS
Utility Plant
Plant in Service	$	7,918,549	$	7,813,680

Construction Work in Progress	333,477		256,044
Total Utility Plant	8,252,026		8,069,724
Accumulated Depreciation and Amortization	(2,653,194)		(2,603,730)

Total Utility Plant, Net	5,598,832		5,465,994

Investments and Other Property	65,402		74,128

Current Assets
Cash and Cash Equivalents	52,835		16,237
Accounts Receivable (Net of Allowance for Credit Losses of $8,760 and $9,012)	205,479		320,899
Fuel Inventory	37,827		28,681
Materials and Supplies	164,652		155,650
Regulatory Assets	163,327		185,034
Derivative Instruments	26,539		27,019

Other	30,019		30,547
Total Current Assets	680,678		764,067
Regulatory and Other Assets
Regulatory Assets	177,814		184,894
Derivative Instruments	38,330		77,123
Other	134,234		123,575
Total Regulatory and Other Assets	350,378		385,592
Total Assets	$	6,695,290	$	6,689,781

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	June 30, 2023		December 31, 2022
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2023 and December 31, 2022)	$	1,702,439	$	1,696,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	1,007,986		968,367
Accumulated Other Comprehensive Loss	(2,829)		(2,884)
Total Common Stock Equity	2,701,239		2,655,665
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2023 and December 31, 2022)	—		—

Long-Term Debt, Net	2,395,534		2,114,980
Total Capitalization	5,096,773		4,770,645
Current Liabilities
Current Maturities of Long-Term Debt, Net	—		149,957


Accounts Payable	133,726		233,920
Accrued Taxes Other Than Income Taxes	54,657		58,914
Accrued Employee Expenses	30,037		38,459
Accrued Interest	19,710		14,868
Regulatory Liabilities	98,465		110,782
Customer Deposits	14,841		14,073
Derivative Instruments	11,078		12,752
Other	46,516		49,163
Total Current Liabilities	409,030		682,888
Regulatory and Other Liabilities
Deferred Income Taxes, Net	607,473		590,926
Regulatory Liabilities	320,251		377,546
Pension and Other Postretirement Benefits	69,667		69,048
Derivative Instruments	3,060		4,787
Other	189,036		193,941
Total Regulatory and Other Liabilities	1,189,487		1,236,248

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	6,695,290	$	6,689,781

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

(Concluded)

TUCSON ELECTRIC POWER COMPANY

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

(Amounts in thousands)


	Three Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of March 31, 2022	$	1,696,539	$	(6,357)	$	870,362	$	(9,718)	$	2,550,826
Net Income					54,974				54,974
Other Comprehensive Income, Net of Tax							197		197



Balances as of June 30, 2022	$	1,696,539	$	(6,357)	$	925,336	$	(9,521)	$	2,605,997


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, 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


	Six Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2021	$	1,696,539	$	(6,357)	$	850,942	$	(9,915)	$	2,531,209
Net Income					74,394				74,394
Other Comprehensive Income, Net of Tax							394		394



Balances as of June 30, 2022	$	1,696,539	$	(6,357)	$	925,336	$	(9,521)	$	2,605,997


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, 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

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 445,000 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 subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2022 Annual Report on Form 10-K.

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

Variable Interest Entities

A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is the primary beneficiary of the VIEs on a quarterly basis.

As of June 30, 2023, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term renewable PPAs were predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Restricted Cash

Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows:


	Six Months Ended June 30,
(in millions)	2023		2022
Cash and Cash Equivalents	$	53	$	146
Restricted Cash included in:
Investments and Other Property	19		19
Current Assets—Other	13		3
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	85	$	168

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 $4 million and $9 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2023, respectively, and $6 million and $8 million for the three and six months ended June 30, 2022, respectively.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) has been adopted and reflected in TEP's financial statements as of June 30, 2023. Adoption of the new guidance had an insignificant impact on TEP's financial position, results of operations, cash flows, and disclosures.

Reference Rate Reform

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

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

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

NOTE 2. REGULATORY MATTERS

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

RATE CASE MATTERS

2022 Rate Case

In 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021. TEP requested new rates to be implemented by September 1, 2023.

On July 12, 2023, an ACC ALJ issued a ROO in TEP's 2022 Rate Case. Key recommendations of the ROO, include:

•a non-fuel retail revenue increase of $102 million over test year non-fuel retail revenues;

•a 6.85% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.40% and an average cost of debt of 3.82%;

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

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

•the establishment of a second phase of the 2022 Rate Case to consider updates to TEP's PPFAC plan of administration.

In January 2023, the ACC ordered that the just and equitable transition away from fossil-based generation facilities be considered as part of the 2022 Rate Case. The ROO proposes establishing a task force to review matters related to just and equitable transition but proposes no ratepayer funding for the transition as part of the 2022 Rate Case. TEP cannot predict the timing or outcome of this proceeding.

OTHER FERC MATTERS

In January 2021, the FERC notified TEP that it was commencing an audit with the intent to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covered the period of January 1, 2018 to December 31, 2021. In November 2022, the FERC published its findings and recommendations. TEP accepted the findings therein and, in May 2023, issued refunds to customers of $1 million related to the audit. All compliance activities related to the audit were completed by the end of the second quarter of 2023, and a final status update was submitted to the FERC on July 28, 2023.

COST RECOVERY MECHANISMS

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

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period.

In April 2022, the ACC approved a rate adjustment for the PPFAC that set the true-up component of the PPFAC rate to recover the then existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which contributed to under-collection of PPFAC costs. In May 2023, the ACC approved a rate adjustment for the PPFAC to collect the remaining uncollected balance over 12 months.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Beginning of Period	$	118	$	102	$	124	$	91
Deferred Fuel and Purchased Power Costs (1)	65		88		123		153
PPFAC and Base Power Recoveries	(90)		(87)		(154)		(141)
End of Period	$	93	$	103	$	93	$	103

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

Transmission Cost Adjustor

The Transmission Cost Adjustor (TCA) allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. TEP files new TCA rates with the ACC in December each year based on changes in the OATT formula rate. New TCA rates take effect in January of each year.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2023 is 13% of retail electric sales. Consistent with prior years, TEP expects to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES Tariff.

In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. In June 2023, the ACC approved an extension of the 2021 RES implementation plan through 2024.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards. The Energy Efficiency Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs of implementing DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year.

In November 2022, the ACC approved TEP’s 2022 energy efficiency implementation plan, with a budget of $24 million, which is collected through the DSM surcharge. The 2022 plan will remain in effect until another plan is approved.

In March 2022, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings over three years.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

REGULATORY ASSETS AND LIABILITIES

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


($ in millions)	Remaining Recovery Period (years)	June 30, 2023		December 31, 2022
Regulatory Assets
Under Recovered Purchased Energy Costs	1	$	93	$	124
Pension and Other Postretirement Benefits (Note 8)	Various	87		90
Early Generation Retirement Costs	Various	55		58
Lost Fixed Cost Recovery	1	33		25
Property Tax Deferrals (1)	1	30		29
Final Mine Reclamation and Retiree Healthcare Costs (2)	6	11		11
Income Taxes Recoverable through Future Rates (3)	Various	6		6
Unamortized Loss on Reacquired Debt	Various	5		5
Derivatives (Note 9)	7	3		3


Other Regulatory Assets	Various	18		19
Total Regulatory Assets		341		370
Less Current Portion	1	163		185
Total Non-Current Regulatory Assets		$	178	$	185


Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	236	$	244
Renewable Energy Standard	Various	73		73
Derivatives (Note 9)	7	39		86
Net Cost of Removal (4)	Various	31		43
Demand Side Management	1	15		16
Transmission Balancing Accounts	1	9		9
Pension and Other Postretirement Benefits (Note 8)	Various	8		8
Deferred Investment Tax Credits	Various	7		7


Other Regulatory Liabilities	Various	—		3



Total Regulatory Liabilities		418		489
Less Current Portion	1	98		111
Total Non-Current Regulatory Liabilities		$	320	$	378

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

(2)Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022.

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

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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. TEP pays a return on most of its regulatory liability balances.

NOTE 3. REVENUE

DISAGGREGATION OF REVENUES

TEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Retail	$	297	$	306	$	530	$	524
Wholesale (1)	64		99		190		155
Other Services	39		23		70		47
Revenues from Contracts with Customers	400		428		790		726
Alternative Revenues	8		2		21		13
Other	10		10		43		37
Total Operating Revenues	$	418	$	440	$	854	$	776

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

NOTE 4. ACCOUNTS RECEIVABLE

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


(in millions)	June 30, 2023		December 31, 2022
Retail	$	92	$	87
Retail, Unbilled	60		46
Retail, Allowance for Credit Losses	(9)		(9)
Wholesale (1)	32		132
Due from Affiliates (Note 5)	15		26
Other	15		39
Accounts Receivable	$	205	$	321

(1)Includes $8 million as of June 30, 2023, and $52 million as of December 31, 2022, of receivables related to revenue from derivative instruments.

ALLOWANCE FOR CREDIT LOSSES

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Beginning of Period	$	(8)	$	(9)	$	(9)	$	(10)
Credit Loss Expense	(1)		(1)		(2)		(1)
Write-offs	—		2		2		3

End of Period	$	(9)	$	(8)	$	(9)	$	(8)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5. RELATED PARTY TRANSACTIONS

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

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


(in millions)	June 30, 2023		December 31, 2022
Receivables from Related Parties
UNS Electric	$	13	$	22
UNS Gas	2		2
UNS Energy	—		2








Total Due from Related Parties	$	15	$	26

Payables to Related Parties
UNS Electric	$	2	$	5
UNS Energy	1		1



UNS Gas	—		1

Total Due to Related Parties	$	3	$	7

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Goods and Services Provided by TEP to Affiliates
Wholesale Revenues, UNS Electric (1)	$	6	$	9	$	13	$	10
Common Costs, UNS Energy Affiliates (2)	5		6		11		11
Transmission Revenues, UNS Electric (1)	2		1		4		3
Control Area Services, UNS Electric (3)	1		1		1		2


Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (4)	$	1	$	2	$	4	$	5
Corporate Services, UNS Energy Affiliates (5)	1		1		1		1
Purchased Power, UNS Electric (1)	—		—		1		—

Capacity Charges, UNS Gas (6)	—		—		1		—

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

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

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

(4)Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million and $4 million for the three and six months ended June 30, 2023 and 2022, respectively.

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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 6. DEBT AND CREDIT AGREEMENT

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

DEBT

Issuance and Redemptions

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

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

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

CREDIT AGREEMENT

In June 2023, the 2021 Credit Agreement was amended to provide for the transition to SOFR-based borrowings. As of June 30, 2023, the amended agreement provides for borrowings at SOFR for the respective term plus an adjustment of 0.10%, plus an applicable margin of 1.025% or at an Alternate Base Rate plus 0.025%.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

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

Fuel, Including Transportation

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

CONTINGENCIES

Legal Matters

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

Mine Reclamation at Generation Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation costs are subject to various assumptions, such as: (i) estimations of reclamation costs; (ii) timing of when final reclamation will occur; and (iii) the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s share of final mine reclamation costs at Four Corners is $7 million upon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the coal supply agreement in June 2022. As of June

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

30, 2023, TEP’s remaining final mine reclamation liability at San Juan was $29 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to occur by 2039. See Note 1 for additional information on restricted cash.

TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation totaled $34 million and $37 million as of June 30, 2023, and December 31, 2022, respectively, and was recorded in Other on the Condensed Consolidated Balance Sheets.

Performance Guarantees

TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. There is no cap on the potential amount of future payments TEP could be required to make under the Luna guarantee. The aggregate maximum potential amount of future payments to the non-defaulting parties is $250 million at Four Corners. As of June 30, 2023, there have been no such payment defaults under either of the participation agreements.

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

Environmental Matters

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2023		2022		2023		2022
Service Cost	$	3	$	5	$	1	$	2
Non-Service Cost (1)
Interest Cost	6		4		1		1
Expected Return on Plan Assets	(7)		(10)		(1)		(1)
Amortization of Net Loss	1		2		—		—
Net Periodic Benefit Cost	$	3	$	1	$	1	$	2


	Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Service Cost	$	6	$	10	$	2	$	3
Non-Service Cost (1)
Interest Cost	11		8		2		1
Expected Return on Plan Assets	(14)		(19)		(1)		(1)
Amortization of Net Loss	2		4		—		—
Net Periodic Benefit Cost	$	5	$	3	$	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 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

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


	Level 1		Level 2		Total
(in millions)	June 30, 2023
Assets
Cash Equivalents (1)	$	15	$	—	$	15
Restricted Cash (1)	26		—		26
Energy Derivative Contracts, Regulatory Recovery (2)	—		48		48
Energy Derivative Contracts, No Regulatory Recovery (2)	—		17		17
Total Assets	41		65		106
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(14)		(14)

Total Liabilities	—		(14)		(14)
Total Assets (Liabilities), Net	$	41	$	51	$	92


(in millions)	December 31, 2022
Assets

Restricted Cash (1)	$	35	$	—	$	35
Energy Derivative Contracts, Regulatory Recovery (2)	—		100		100
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	35		104		139
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(18)		(18)


Total Liabilities	—		(18)		(18)
Total Assets (Liabilities), Net	$	35	$	86	$	121

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

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

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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 on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:


	Gross Amount Recognized in the Balance Sheets		Gross Amount Not Offset in the Balance Sheets				Net Amount
			Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted
(in millions)	June 30, 2023
Derivative Assets
Energy Derivative Contracts	$	65	$	13	$	—	$	52
Derivative Liabilities
Energy Derivative Contracts	(14)		(13)		—		(1)


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

DERIVATIVE INSTRUMENTS

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

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

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

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.

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Energy Derivative Contracts, Regulatory Recovery

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Unrealized Net Gain (Loss) (1)	$	(5)	$	18	$	(47)	$	107

(1)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. For the three and six months ended June 30, 2022, unrealized net gain on regulatory recoverable derivative contracts was primarily due to increases in forward market prices of natural gas.

Energy Derivative Contracts, No Regulatory Recovery

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Operating Revenues	$	4	$	2	$	17	$	10

Derivative Volumes

As of June 30, 2023, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:


	June 30, 2023	December 31, 2022
Power Contracts GWh	4,084	1,979
Gas Contracts BBtu	98,991	96,755

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.

TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.

TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to individual contracts.

The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $22 million as of June 30, 2023, compared with $86 million as of December 31, 2022. As of June 30, 2023, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on June 30, 2023, TEP would have been required to post $22 million of collateral. As of June 30, 2023, TEP had $15 million in outstanding net payable balances for settled positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

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

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


	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		June 30, 2023		December 31, 2022		June 30, 2023		December 31, 2022
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,396	$	2,265	$	2,068	$	1,901

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

NON-CASH TRANSACTIONS

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


	Six Months Ended June 30,
(in millions)	2023		2022
Accrued Capital Expenditures	$	31	$	25

Renewable Energy Credits	6		5

Asset Retirement Obligation/Cost Increase (Decrease) (1)	(1)		(28)
Net Cost of Removal Increase (Decrease) (2)	(9)		(46)

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

(2)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset.

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

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

•outlook and strategies;

•factors affecting results of operations;

•results of operations;

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

•critical accounting estimates; and

•new accounting standards issued and adopted or not yet adopted.

Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP.

Management’s Discussion and Analysis should be read in conjunction with the condensed consolidated financial statements and accompanying notes that appear in Part I, Item 1 of this Form 10-Q. For information on factors that may cause our actual future results to differ from those we currently anticipate, see Forward-Looking Information at the front of this Form 10-Q and Risk Factors in Part 1, Item 1A of our 2022 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.

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

OUTLOOK AND STRATEGIES

Our financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws, regulations, and policies; and (iv) other regulatory and legislative actions. Our plans and strategies include:

•Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers.

•Continuing our transition from carbon-intensive sources to a more sustainable energy portfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. Our goal is to reduce carbon emissions by 80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In 2022, Fortis set a goal to achieve net-zero direct GHG emissions by 2050. The establishment of this additional target reinforces Fortis' commitment, along with that of its subsidiaries, to decarbonize over the long-term, while preserving customer reliability and affordability. These goals may be impacted by various federal and state energy policies, including policies currently under consideration.

•Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.

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

We reported net income of $48 million in the second quarter of 2023 compared with net income of $55 million in the second quarter of 2022. The decrease of $7 million, or 13%, was primarily due to:

•$8 million in lower retail revenue primarily due to lower usage as a result of unfavorable weather; partially offset by increased LFCR revenue;

•$3 million in lower margin from wholesale transactions primarily due to a decrease in sales volume;

•$3 million in higher base operations and maintenance expenses primarily due to increases in employee wages and benefits and outside services expenses, and an increase in costs at our generation facilities as a result of higher planned

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outages and maintenance costs in 2023; partially offset by lower remote plant expenses due to the retirement of San Juan Unit 1 in June 2022;

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

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

The decrease was partially offset by:

•$6 million in lower depreciation expense primarily due to the retirement of San Juan Unit 1 in June 2022;

•$5 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of more favorable market conditions; and

•$4 million increase in interest income due to an increase in the interest rate on PPFAC balances.

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

We reported net income of $95 million in the first six months of 2023 compared with net income of $74 million in the first six months of 2022. The increase of $21 million, or 28%, was primarily due to:

•$12 million in lower depreciation expense primarily due to the retirement of San Juan Unit 1 in June 2022;

•$9 million in higher margin from wholesale transactions primarily due to higher prices;

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

•$6 million increase in interest income due to an increase in the interest rate on PPFAC balances.

The increase was partially offset by:

•$5 million in higher net periodic non-service costs as a result of increased interest cost and a decrease in expected return on plan assets;

•$5 million in higher base operations and maintenance expenses primarily due to increases in employee wages and benefits and outside services expenses, and an increase in costs at our generation facilities as a result of higher planned outages and maintenance costs in 2023; partially offset by lower remote plant expenses due to the retirement of San Juan Unit 1 in June 2022;

•$4 million in higher interest expense primarily due to the issuance of debt in February 2023; and

•$3 million in lower retail revenue primarily due to lower usage as a result of unfavorable weather; partially offset by increased LFCR revenue.

FACTORS AFFECTING RESULTS OF OPERATIONS

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

Regulatory Matters

We are subject to comprehensive regulation. The discussion below contains material developments in those matters.

2022 Rate Case

In 2022, we filed a general rate case with the ACC based on a test year ended December 31, 2021. We requested new rates to be implemented by September 1, 2023.

On July 12, 2023, an ACC ALJ issued a ROO in our 2022 Rate Case. Key recommendations of the ROO, include:

•a non-fuel retail revenue increase of $102 million over test year non-fuel retail revenues;

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•a 6.85% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.40% and an average cost of debt of 3.82%;

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

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

•the establishment of a second phase of our 2022 Rate Case to consider updates to our PPFAC plan of administration.

In January 2023, the ACC ordered that the just and equitable transition away from fossil-based generation facilities be considered as part of the 2022 Rate Case. The ROO proposes establishing a task force to review matters related to just and equitable transition but proposes no ratepayer funding for the transition as part of the 2022 Rate Case. We cannot predict the timing or outcome of this proceeding.

Generation Resource Strategy

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

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

Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations and policies, and, for jointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we plan to exit all ownership interests in coal-fired generation facilities over the next decade. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions. The execution of our 2020 IRP is dependent on obtaining regulatory recovery in future rate proceedings. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the 2022 Rate Case.

Oso Grande

Production Tax Credits

PTCs are per kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In May 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded approximately $4 million and $9 million in PTCs related to Oso Grande, for the three and six months ended June 30, 2023, respectively, and $6 million and $8 million, for the three and six months ended June 30, 2022. The PTC rate published by the Internal Revenue Service for electricity produced by a qualified facility using wind placed in service prior to 2022 is $0.028 for 2023 and was $0.026 for 2022.

The PTCs will offset most of the operating expenses of Oso Grande until the project is included in rates, which we requested as part of our 2022 Rate Case. Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, the project’s electricity generation and associated PTCs may be substantially different than forecasted.

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Weather Patterns

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

Interest Rates

See Part II, Item 7A in our 2022 Annual Report on Form 10-K and Part I, Item 3 of this Form 10-Q for information regarding interest rate risk and its impact on earnings.

RESULTS OF OPERATIONS

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

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

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

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

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The following discussion provides the significant items that affected our results of operations in the second quarter and first six months of 2023 compared with the same periods in 2022 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:


	Three Months Ended June 30,				Increase (Decrease)		Six Months Ended June 30,				Increase (Decrease)
(in millions)	2023		2022		Percent		2023		2022		Percent
Operating Revenues
Retail	$	297	$	306	(2.9)	%	$	530	$	524	1.1	%
Wholesale, Short-Term (1)	42		63		(33.3)	%	136		109		24.8	%
Wholesale, Long-Term	13		25		(48.0)	%	42		42		—	%
Transmission	12		14		(14.3)	%	29		27		7.4	%
Springerville Units 3 and 4 Participant Billings	36		19		89.5	%	63		39		61.5	%
Other	18		13		38.5	%	54		35		54.3	%
Total Operating Revenues	$	418	$	440	(5.0)	%	$	854	$	776	10.1	%

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

We reported Operating Revenues of $418 million in the second quarter of 2023 compared with $440 million in the same period for 2022. The decrease of $22 million, or 5%, was primarily due to:

•$21 million in lower short-term wholesale revenue primarily due to a decrease in price;

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

•$9 million in lower retail revenue primarily due to lower usage as a result of unfavorable weather.

The decrease was partially offset by $17 million in higher participant billings primarily related to Springerville Units 3 and 4.

We reported Operating Revenues of $854 million for the first six months of 2023 compared with $776 million in the same period for 2022. The increase of $78 million, or 10%, was primarily due to:

•$27 million in higher short-term wholesale revenue primarily due to an increase in price; partially offset by a decrease in volume;

•$24 million in higher participant billings primarily related to Springerville Units 3 and 4;

•$19 million in higher other service revenue primarily due to an increase in market prices related to a natural gas transportation asset management agreement, higher RES and DSM surcharge revenue, and higher LFCR revenue; and

•$6 million in higher retail revenue primarily due to higher PPFAC cost recoveries as a result of a higher PPFAC rate; partially offset by lower usage as a result of unfavorable weather.

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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)	2023	2022	Percent		2023	2022	Percent
Electric Sales (kWh) (1)
Retail Sales	2,162	2,323	(6.9)	%	3,984	4,112	(3.1)	%
Wholesale, Long-Term (2)	257	416	(38.2)	%	731	725	0.8	%
Wholesale, Short-Term	1,100	1,101	(0.1)	%	2,041	2,204	(7.4)	%
Total Electric Sales	3,519	3,840	(8.4)	%	6,756	7,041	(4.0)	%

Average Revenue per kWh (2)
Retail	13.75	13.18	4.3	%	13.31	12.74	4.5	%
Wholesale, Long-Term	4.96	5.94	(16.5)	%	5.68	5.86	(3.1)	%
Wholesale, Short-Term	3.49	5.65	(38.2)	%	5.85	4.54	28.9	%

Total Retail Customers (3)					445,343	441,573	0.9	%

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

(2)This metric represents the amount earned per kWh for retail and wholesale revenue. This number is calculated as revenue divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.

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

Operating Expenses

Fuel and Purchased Power Expense

We reported Fuel and Purchased Power expense of $154 million in the second quarter of 2023 compared with $178 million in the same period for 2022. The decrease of $24 million, or 13%, was primarily due to:

•$41 million in lower fuel costs primarily due to a decrease in natural gas prices and a decrease in Coal-Fired Generation volumes; partially offset by an increase in realized losses on natural gas swap agreements and an increase in Gas-Fired Generation volumes; and

•$6 million in lower purchased energy costs primarily due to a decrease in volume and price.

The decrease was partially offset by a $29 million decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery and an increase in PPFAC cost recoveries.

We reported Fuel and Purchased Power expense of $339 million for the first six months of 2023 compared with $296 million for the same period for 2022. The increase of $43 million, or 15%, was primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery and an increase in PPFAC cost recoveries.

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


	Three Months Ended June 30,		Increase (Decrease)		Six Months Ended June 30,		Increase (Decrease)
(kWh in millions)	2023	2022	Percent		2023	2022	Percent
Sources of Energy
Coal-Fired Generation	594	1,345	(55.8)	%	1,575	2,646	(40.5)	%
Gas-Fired Generation	1,833	1,482	23.7	%	3,415	2,804	21.8	%
Utility-Owned Renewable Generation	193	268	(28.0)	%	423	477	(11.3)	%
Total Generation	2,620	3,095	(15.3)	%	5,413	5,927	(8.7)	%
Purchased Power, Non-Renewable	611	542	12.7	%	790	740	6.8	%
Purchased Power, Renewable	419	433	(3.2)	%	774	746	3.8	%
Total Generation and Purchased Power (1)	3,650	4,070	(10.3)	%	6,977	7,413	(5.9)	%


(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal	3.21	2.60	23.5	%	3.02	2.57	17.5	%
Natural Gas (3)	2.34	4.48	(47.8)	%	4.03	4.11	(1.9)	%
Average Cost of Purchased Power (4)
Purchased Power, Non-Renewable	4.27	6.58	(35.1)	%	5.39	6.38	(15.5)	%
Purchased Power, Renewable	6.93	6.71	3.3	%	6.71	6.71	—	%

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

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

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

(4)This metric represents cost as cents per kWh for renewable and non-renewable purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh) for each respective form of purchased power. Management uses this metric to compare and monitor the costs of renewable and non-renewable purchased power.

Operations and Maintenance Expense

We reported Operations and Maintenance expense of $120 million in the second quarter of 2023 compared with $101 million in the same period for 2022. The increase of $19 million, or 19%, was primarily due to higher reimbursable maintenance expense related to Springerville Unit 3 primarily due to planned outages.

We reported Operations and Maintenance expense of $228 million for the first six months of 2023 compared with $199 million for the same period for 2022. The increase of $29 million, or 15%, was primarily due to higher reimbursable maintenance expense related to Springerville Unit 3 primarily due to planned outages.

Depreciation and Amortization Expense

We reported Depreciation and Amortization expense of $57 million in the second quarter of 2023 compared with $64 million in the same period for 2022. The decrease of $7 million, or 11%, was primarily due to the retirement of San Juan Unit 1 in June 2022.

We reported Depreciation and Amortization expense of $114 million for the first six months of 2023 compared with $128 million for the same period for 2022. The decrease of $14 million, or 11%, was primarily due to the retirement of San Juan Unit 1 in June 2022.

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Other Income (Expense)

We reported other expenses of $16 million in the second quarter of 2023 compared with $18 million in the same period for 2022. The decrease of $2 million, or 11%, was primarily due to:

•$4 million in higher interest income primarily due to an increase in the interest earned on the PPFAC regulatory asset; and

•$4 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of more favorable market conditions.

The decrease was partially offset by:

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

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

We reported other expenses of $32 million for the first six months of 2023 compared with $37 million for the same period for 2022. The decrease of $5 million, or 14%, was primarily due to:

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

•$7 million in higher interest income primarily due to an increase in the interest earned on the PPFAC regulatory asset.

The decrease was partially offset by:

•$6 million in higher net periodic non-service cost primarily due to an increase in interest cost and a decrease in expected return on plan assets; and

•$5 million in higher interest expense primarily due to the issuance of debt in February 2023.

Income Tax Expense

We reported Income Tax Expense of $13 million for the first six months of 2023 compared with $10 million for the same period for 2022. The increase of $3 million, or 30%, was primarily due to $6 million in higher tax expense due to an increase in taxable earnings. The increase was partially offset by $2 million in lower tax expense due to a non-taxable gain on the value of investments used to support certain post-employment benefits.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Any extended period of economic disruption could affect our business and financial conditions and access to sources of liquidity. Cash flows vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to our summer peaking load. Market risks associated with fluctuations in commodity prices can temporarily affect our cash flows due to timing of recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. We use our revolving credit as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.

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Available Liquidity


(in millions)	June 30, 2023
Cash and Cash Equivalents	$	53
Amount Available under Revolving Credit Agreement (1)	245
Total Liquidity	$	298

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

Future Liquidity Requirements

We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include but are not limited to: (i) dividend payments; (ii) debt maturities; (iii) employee benefit obligations; and (iv) known commitments and other contractual obligations including forecasted capital expenditures.

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

Summary of Cash Flows

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


	Six Months Ended June 30,				Increase (Decrease)
(in millions)	2023		2022		Percent
Operating Activities	$	215	$	259	(17.0)	%
Investing Activities (1)	(260)		(240)		8.3	%
Financing Activities	79		116		(31.9)	%
Net Increase (Decrease)	34		135		(74.8)	%
Beginning of Period	51		33		54.5	%
End of Period	$	85	$	168	(49.4)	%

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

Operating Activities

Net cash flows provided by operating activities decreased by $44 million in the first six months of 2023 compared with the same period in 2022. The decrease was primarily due to: (i) changes in working capital primarily due to a decrease in wholesale energy balances primarily due to lower prices and cash collateral deposits received from counterparties in 2022, not recurring in 2023; and (ii) lower retail revenue primarily due to unfavorable weather. The decrease was partially offset by: (i) higher margin from wholesale transactions; and (ii) higher PPFAC cost recoveries as a result of a higher PPFAC rate.

Investing Activities

Net cash flows used for investing activities increased by $20 million in the first six months of 2023 compared with the same period in 2022 primarily due to an increase in cash paid for capital expenditures.

Financing Activities

Net cash flows provided by financing activities decreased by $37 million in the first six months of 2023 compared with the same period in 2022 primarily due to an increase in dividends declared and paid to UNS Energy; partially offset by lower repayments of credit facility borrowings.

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Sources of Liquidity

Short-Term Investments

Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of June 30, 2023, our short-term investments were deposited in insured cash sweep and money market accounts.

Access to Credit

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

In June 2023, the 2021 Credit Agreement was amended to provide for the transition to SOFR-based borrowings. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding our 2021 Credit Agreement and Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2022 Annual Report on Form 10-K for additional information regarding our 2021 Credit Agreement.

Debt Financing

We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings. In December 2020, the ACC issued an order granting our financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate.

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

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

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

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

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of June 30, 2023, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- and A3, respectively.

Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold our securities. Each rating should be evaluated independently of any other ratings.

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

Debt Covenants

Under certain agreements, should we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of June 30, 2023, we were in compliance with these covenants.

We do not have any provisions in any of our debt agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.

Contributions from Parent

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

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Dividends Declared and Paid to Parent

We declared and paid $55 million in dividends to UNS Energy in the second quarter and first six months of 2023. We did not declare or pay dividends to UNS Energy in the second quarter or first six months of 2022.

Master Trading Agreements

We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of June 30, 2023, 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 six months of 2023, there were no material changes to our forecasted capital expenditures as reported in our 2022 Annual Report on Form 10-K.

Income Tax Position

On August 16, 2022, President Biden signed the IRA into law. Among other provisions, the legislation enacted a new Corporate Alternative Minimum Tax (CAMT) of 15% that is effective for tax years beginning after December 31, 2022. We are currently subject to the CAMT due to our membership in the Fortis consolidated tax group.

Under the terms of the tax sharing agreement with UNS Energy, we received $4 million in tax sharing payments for the first six months of 2023 and made $2 million in tax sharing payments for the first six months of 2022. Future cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.

Collective Bargaining Agreements

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

Environmental Matters

The Environmental Protection Agency (EPA) has the authority to regulate the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. We expect recovery of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.

Regional Haze Regulations

The EPA's Regional Haze rule requires emission reductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas (Regional Haze). The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a State Implementation Plan (SIP) and must review and submit revisions to the SIP on a periodic basis.

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

We conducted the potential emissions controls evaluation, commonly referred to as the four factor analysis, for both facilities. These evaluations were submitted to the ADEQ in March 2020 for the agency's use in developing the revised SIP. In August 2022, the ADEQ submitted the revised SIP to the EPA, and the EPA issued a letter to the ADEQ finding Arizona's SIP revision complies with the completeness criteria outlined in the rule. By statute, the EPA has one year from the completeness determination to take action on Arizona's SIP revision. Based on current Regional Haze requirement timeframes, we anticipate that compliance strategies, if any, will likely be required to be implemented two years after the ADEQ's submission of the

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revised SIP to the EPA. We cannot predict the outcome of this matter but will continue to work with the ADEQ to determine compliance strategies as needed.

Greenhouse Gas Regulation

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

In June 2019, the EPA repealed the CPP and issued the Affordable Clean Energy (ACE) rule, establishing new emission guidelines for existing coal-fired generation facilities based on the Best System of Emission Reduction (BSER) for GHG emissions. The BSER for GHG emissions from existing coal-fired generation facilities is defined as Heat-Rate Improvements that can be applied at the source. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the remaining useful life of an individual unit.

In 2021, the U.S. Court of Appeals for the D.C. Circuit: (i) vacated the EPA's repeal of the CPP and remanded it back to the EPA for further consideration (the vacatur was later stayed by the court); and (ii) vacated and remanded the ACE rule. Certain petitioners, defending the repeal of the CPP, filed petitions for an order requesting that the U.S. Supreme Court review the decision of the lower court. The U.S. Supreme Court granted the petitions, consolidated the cases, and in June 2022, reversed the D.C. Circuit and remanded the cases back for further proceedings.

In May 2023, the EPA published a proposed GHG rule addressing GHG emissions from fossil fuel-fired electric generating units. The proposed rule also provides for the repeal of the ACE rule. The public comment period closes in August 2023. We are analyzing the EPA's proposed rule and cannot predict the outcome of these matters at this time.

Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring the disposal of coal ash and other Coal Combustion Residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act for disposal in landfills and/or surface impoundments. Our share of costs to comply with the CCR rule at Four Corners is estimated to be $3 million. This includes estimated costs for corrective action for two CCR units at the facility. Arizona Public Service Company (APS), the operating agent of Four Corners, began an assessment of corrective measures in 2019 and completed the assessment in 2022. The proposed final remedy was presented to the public in August 2022, and a final remedy report is being prepared.

The EPA published a proposed Legacy CCR Surface Impoundments Rule in May 2023. As currently proposed, the rule will cover legacy CCR impoundments at inactive facilities and historical placement of non-containerized CCR on land at either active or inactive facilities, including CCR historically used as structural fill material. The public comment period closed in July 2023. We are analyzing the EPA’s proposed rule and cannot predict the outcome of this matter.

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 six months ended June 30, 2023, to the items that we disclosed as our critical accounting estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2022 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED OR NOT YET ADOPTED

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2022 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures were effective as of June 30, 2023. There was no change in TEP’s internal control over financial reporting during the quarter ended June 30, 2023, that materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

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

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

ITEM 1A. RISK FACTORS

The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2022 Annual Report on Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2022 Annual Report on Form 10-K.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.

Description

*4(1 )

Amendment No. 1 to Amended and Restated Credit Agreement, dated as of June 8, 2023, by and among Tucson Electric Power Company, as Borrower, the Lenders party thereto and MUFG Bank, Ltd. (as successor by assignment from MUFG Union Bank, N.A.), as Administrative Agent.

*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 June 30, 2023, formatted in Inline XBRL and contained in Exhibit 101


*			Filed herewith.
**			Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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:	August 1, 2023	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President, Chief Financial Officer, and Director
		(Principal Financial Officer)