Tucson Electric Power Co.

11/05/2024 | Press release | Distributed by Public on 11/05/2024 05:16

Quarterly Report for Quarter Ending September 30, 2024 (Form 10-Q)

tep-20240930
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2024
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
Arizona 86-0062700
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
88 East Broadway Boulevard, Tucson, AZ 85701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (520) 571-4000
Former name, former address, and former fiscal year, if changed since last report: N/A
Securities registered pursuant to Section 12(b) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer ☐ Accelerated Filer ☐ Non-Accelerated Filer ☒ Smaller Reporting Company ☐ Emerging Growth Company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐No ☒
All shares of outstanding common stock of Tucson Electric Power Company are held by its parent company, UNS Energy Corporation, which is an indirect, wholly-owned subsidiary of Fortis Inc. There were 32,139,434 shares of common stock, no par value, outstanding as of November 4, 2024.
Table of Contents
Definitions
iii
Forward-Looking Information
iv
PART I
Item 1. Financial Statements
Condensed Consolidated Statements of Income
1
Condensed Consolidated Statements of Cash Flows
2
Condensed Consolidated Balance Sheets
3
Condensed Consolidated Statements of Changes in Stockholder's Equity
5
Notes to Condensed Consolidated Financial Statements
6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
20
Critical Accounting Estimates
33
New Accounting Standards Issued and Not Yet Adopted
33
Item 3. Quantitative and Qualitative Disclosures about Market Risk
33
Item 4. Controls and Procedures
33
PART II
Item 1. Legal Proceedings
34
Item 1A. Risk Factors
34
Item 6. Exhibits
35
Signatures
36
ii
DEFINITIONS
The abbreviations and acronyms used in this Quarterly Report on Form 10-Q are defined below:
INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS
2023 IRP TEP's 2023 Integrated Resource Plan which outlines TEP's aspirational goal to reach net zero direct greenhouse gas emissions by 2050
2020 IRP TEP's 2020 Integrated Resource Plan which outlines TEP's plan to reduce its carbon emissions by 80% compared to 2005 by 2035
2021 Credit Agreement
The 2021 Credit Agreement, as amended in June 2023 and extended in October 2024, 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 2027
2023 Rate Order Order issued by the ACC resulting in a new rate structure for TEP, effective on September 1, 2023
ABR Alternate Base Rate
ACC Arizona Corporation Commission
ADEQ Arizona Department of Environmental Quality
ADJ SOFR Rate Spread Adjustment
AFUDC Allowance for Funds Used During Construction
BESS Battery Energy Storage System
CCR Coal Combustion Residuals
DG Distributed Generation
DSM Demand Side Management
EPA Environmental Protection Agency
EPC Engineering, Procurement, and Construction
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles in the United States of America
GHG Greenhouse Gas
IRA Inflation Reduction Act, signed into law on August 16, 2022
LFCR Lost Fixed Cost Recovery
LOC Letter(s) of Credit
OATT Open Access Transmission Tariff
PPA Power Purchase Agreement
PPFAC Purchased Power and Fuel Adjustment Clause
PTC Production Tax Credit
REC Renewable Energy Credit
RES Renewable Energy Standard
Retail Rates Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
SIP State Implementation Plan
SOFR Secured Overnight Financing Rate
TCA Transmission Cost Adjustor
ENTITIES AND GENERATING STATIONS
Fortis Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners Four Corners Power Plant
Navajo Navajo Generating Station
Oso Grande A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico
Roadrunner Reserve I A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in the second half of 2025
Roadrunner Reserve II A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in the second half of 2026
San Juan San Juan Generating Station
Springerville Springerville Generating Station
SRP Salt River Project Agricultural Improvement and Power District
Sundt H. Wilson Sundt Generating Station
TEP Tucson Electric Power Company, the principal subsidiary of UNS Energy
UNS Electric UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy
UNS Energy UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates Affiliated subsidiaries of UNS Energy including UniSource Energy Services, Inc., UNS Electric, and UNS Gas
UNS Gas UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy
UNITS OF MEASURE
BBtu Billion British thermal unit(s)
GWh Gigawatt-hour(s)
kWh Kilowatt-hour(s)
MW Megawatt(s)
MWh Megawatt-hour(s)
iii
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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 or phrases that include "anticipates," "believes," "estimates," "expects," "intends," "aspires," "may," "plans," "predicts," "forecast," "target," "potential," "projects," "would," "strategy," and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany such forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as may otherwise be required by the federal securities laws.
Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed therein. We express our estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management's estimates, expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part I, Item 1A. Risk Factors of our 2023 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Quarterly Report on Form 10-Q; Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations of this Quarterly Report on Form 10-Q; and other parts of this report. These factors include: voter initiatives and federal, state, and local regulatory and legislative decisions and actions, including changes in tax, inclusive of the IRA and evolving interpretive guidance related thereto, and energy policies, including as they may be affected by the policies and priorities of the officials elected in the 2024 presidential, congressional, state, and local elections; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies; changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output, or accelerate generation facility retirements; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; potential changes in the benefits of participation in the Energy Imbalance Market; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality, extreme weather events, and wildfires, affecting electricity usage of our customers, operational performance, and operating and capital costs to ensure system reliability; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital and to use the proceeds from any capital that we do raise as originally intended; the performance of the stock market and a volatile interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and related contribution requirements and expenses; our ability to manage timelines and budgets related to capital projects, including EPC agreements to develop standalone battery energy storage facilities, and/or to obtain the anticipated performance or other benefits of such capital projects; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense, including increases due to inflationary effects, heightened geopolitical instability, and/or global supply chain challenges; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting estimates; the ongoing impact of mandated energy efficiency and DG initiatives; our ability to effectively implement plans to meet our goals related to reducing carbon emissions by 2035 and 2050, and the potential impact on our financial condition; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other cyberspace attacks to our information security and our operations and technology infrastructure, including attacks that may arise from heightened geopolitical instability; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; the extent of the impact of a global health or other crisis on our business and operations, and any economic and/or societal disruptions resulting therefrom and from the government actions taken in response thereto; and the implementation of our 2023 IRP.
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PART I
ITEM 1. FINANCIAL STATEMENTS
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Amounts in thousands)
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Operating Revenues $ 551,632 $ 593,247 $ 1,433,934 $ 1,447,336
Operating Expenses
Fuel 92,063 107,917 257,165 296,617
Purchased Power 50,703 98,081 104,373 181,657
Transmission and Other PPFAC Recoverable Costs 18,904 29,517 52,371 61,478
Increase (Decrease) to Reflect PPFAC Recovery Treatment 26,114 7,659 97,349 42,156
Total Fuel and Purchased Power 187,784 243,174 511,258 581,908
Operations and Maintenance 105,877 103,991 330,143 332,033
Depreciation 56,942 49,901 168,913 144,465
Amortization 7,346 9,487 22,855 28,981
Taxes Other Than Income Taxes 17,384 17,068 53,629 51,448
Total Operating Expenses 375,333 423,621 1,086,798 1,138,835
Operating Income 176,299 169,626 347,136 308,501
Other Income (Expense)
Interest Expense (27,189) (23,986) (75,442) (71,474)
Allowance For Borrowed Funds 2,221 1,279 5,974 3,448
Allowance For Equity Funds 6,276 3,637 16,935 9,779
Unrealized Gains (Losses) on Investments 1,867 (1,331) 2,857 462
Other, Net 2,119 2,463 3,835 8,220
Total Other Income (Expense) (14,706) (17,938) (45,841) (49,565)
Income Before Income Tax Expense 161,593 151,688 301,295 258,936
Income Tax Expense 21,100 23,357 39,187 35,986
Net Income $ 140,493 $ 128,331 $ 262,108 $ 222,950
The accompanying notes are an integral part of these financial statements.
1
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in thousands)
Nine Months Ended September 30,
2024 2023
Cash Flows from Operating Activities
Net Income $ 262,108 $ 222,950
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense 168,913 144,465
Amortization Expense 22,855 28,981
Amortization of Debt Issuance Costs 2,338 2,304
Use of Renewable Energy Credits for Compliance 35,976 33,770
Deferred Income Taxes 28,638 28,649
Pension and Other Postretirement Benefits Expense 13,529 11,398
Pension and Other Postretirement Benefits Funding (17,815) (11,499)
Allowance for Equity Funds Used During Construction (16,935) (9,779)
Change in Long-Term Regulatory Assets and Liabilities 1,546 257
Changes in Current Assets and Current Liabilities:
Accounts Receivable (58,522) 43,869
Materials, Supplies, and Fuel Inventory (22,790) (21,826)
Regulatory Assets 47,446 32,204
Other Current Assets (8,243) (6,112)
Accounts Payable and Accrued Charges 29,976 (62,182)
Income Taxes Receivable/Payable 1,932 1,315
Regulatory Liabilities 53,448 (12)
Other, Net (13,829) (10,415)
Net Cash Flows-Operating Activities 530,571 428,337
Cash Flows from Investing Activities
Capital Expenditures (459,635) (345,470)
Purchase Intangibles, Renewable Energy Credits (46,291) (48,915)
Other Investments - 2,935
Contributions in Aid of Construction 1,314 3,355
Net Cash Flows-Investing Activities (504,612) (388,095)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility 25,000 -
Repayments of Borrowings, Revolving Credit Facility (25,000) -
Proceeds from Issuance, Long-Term Debt-Net of Discount
399,376 373,954
Repayments of Long-Term Debt - (240,745)
Dividend Paid to Parent (85,000) (55,000)
Payment of Debt Issuance Costs (3,221) (4,095)
Contribution from Parent - 5,900
Other, Net 1,369 (383)
Net Cash Flows-Financing Activities 312,524 79,631
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash 338,483 119,873
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 42,595 50,981
Cash, Cash Equivalents, and Restricted Cash, End of Period $ 381,078 $ 170,854
The accompanying notes are an integral part of these financial statements.
2
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
September 30, 2024 December 31, 2023
ASSETS
Utility Plant
Plant in Service $ 8,258,271 $ 8,035,444
Construction Work in Progress 698,880 475,391
Total Utility Plant 8,957,151 8,510,835
Accumulated Depreciation and Amortization (2,683,259) (2,570,157)
Total Utility Plant, Net 6,273,892 5,940,678
Investments and Other Property 67,618 70,080
Current Assets
Cash and Cash Equivalents 354,347 8,616
Accounts Receivable (Net of Allowance for Credit Losses of $12,818 and $11,676 as of September 30, 2024 and December 31, 2023, respectively)
274,461 217,381
Fuel Inventory 36,025 34,475
Materials and Supplies 190,477 172,667
Regulatory Assets 88,905 147,389
Derivative Instruments 10,454 3,091
Other 38,082 30,450
Total Current Assets 992,751 614,069
Regulatory Assets 192,966 182,997
Derivative Instruments 22,980 31,614
Other Noncurrent Assets 149,028 134,196
Total Assets $ 7,699,235 $ 6,973,634
The accompanying notes are an integral part of these financial statements.
(Continued)
3
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
September 30, 2024 December 31, 2023
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2024 and December 31, 2023)
$ 1,696,539 $ 1,696,539
Capital Stock Expense (6,357) (6,357)
Retained Earnings 1,340,029 1,162,921
Accumulated Other Comprehensive Loss (3,638) (3,829)
Total Common Stock Equity 3,026,573 2,849,274
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2024 and December 31, 2023)
- -
Long-Term Debt, Net 2,494,363 2,396,542
Total Capitalization 5,520,936 5,245,816
Current Liabilities
Current Maturities of Long-Term Debt, Net 299,839 -
Accounts Payable 184,683 137,002
Accrued Taxes Other than Income Taxes 81,179 57,291
Accrued Employee Expenses 37,984 39,466
Accrued Interest 31,775 16,541
Regulatory Liabilities 146,556 92,740
Customer Deposits 15,734 15,833
Derivative Instruments 18,470 25,828
Other 41,404 36,312
Total Current Liabilities 857,624 421,013
Deferred Income Taxes, Net 694,281 647,730
Regulatory Liabilities 355,316 396,061
Pension and Other Postretirement Benefits 76,863 81,241
Derivative Instruments 6,709 4,338
Other Noncurrent Liabilities 187,506 177,435
Total Liabilities 2,178,299 1,727,818
Commitments and Contingencies
Total Capitalization and Liabilities $ 7,699,235 $ 6,973,634
The accompanying notes are an integral part of these financial statements.
(Concluded)
4
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited)
(Amounts in thousands)
Three Months Ended
Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of June 30, 2023 $ 1,702,439 $ (6,357) $ 1,007,986 $ (2,829) $ 2,701,239
Net Income 128,331 128,331
Other Comprehensive Income (Loss), Net of Tax 28 28
Balances as of September 30, 2023
$ 1,702,439 $ (6,357) $ 1,136,317 $ (2,801) $ 2,829,598
Balances as of June 30, 2024 $ 1,696,539 $ (6,357) $ 1,284,536 $ (3,737) $ 2,970,981
Net Income 140,493 140,493
Other Comprehensive Income (Loss), Net of Tax 99 99
Dividend Declared to Parent (85,000) (85,000)
Balances as of September 30, 2024
$ 1,696,539 $ (6,357) $ 1,340,029 $ (3,638) $ 3,026,573
Nine Months Ended
Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2022
$ 1,696,539 $ (6,357) $ 968,367 $ (2,884) $ 2,655,665
Net Income 222,950 222,950
Other Comprehensive Income (Loss), Net of Tax 83 83
Dividend Declared to Parent (55,000) (55,000)
Contribution from Parent 5,900 5,900
Balances as of September 30, 2023
$ 1,702,439 $ (6,357) $ 1,136,317 $ (2,801) $ 2,829,598
Balances as of December 31, 2023
$ 1,696,539 $ (6,357) $ 1,162,921 $ (3,829) $ 2,849,274
Net Income 262,108 262,108
Other Comprehensive Income (Loss), Net of Tax 191 191
Dividend Declared to Parent (85,000) (85,000)
Balances as of September 30, 2024
$ 1,696,539 $ (6,357) $ 1,340,029 $ (3,638) $ 3,026,573
The accompanying notes are an integral part of these financial statements.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION
TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 451,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.
BASIS OF PRESENTATION
TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the United States Securities and Exchange Commission's (SEC) interim reporting requirements.
The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2023 Annual Report on Form 10-K.
The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no impact on TEP's results of operation, financial position, or cash flows.
Variable Interest Entities
A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.
TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is the primary beneficiary of the VIEs on a quarterly basis.
As of September 30, 2024, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term renewable PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted Cash
Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows:
Nine Months Ended September 30,
(in millions) 2024 2023
Cash and Cash Equivalents $ 354 $ 138
Restricted Cash included in:
Investments and Other Property 18 20
Current Assets-Other 9 13
Cash, Cash Equivalents, and Restricted Cash, End of Period $ 381 $ 171
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 $10 million and $20 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2024, respectively, and $7 million and $16 million for the three and nine months ended September 30, 2023, respectively.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) and the SEC has not yet been adopted and is not reflected in TEP's financial statements. Unless otherwise indicated, TEP is assessing the impact such guidance may have on TEP's financial position, results of operations, cash flows, and disclosures.
Income Tax Disclosures
In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures.
Reportable Segment Disclosures
In November 2023, the FASB issued accounting guidance that requires disclosure of significant segment expenses and new disclosures for entities with a single reportable segment. The amendments are effective for annual periods beginning on January 1, 2024 and interim periods beginning on January 1, 2025 and are to be applied retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures.
Climate-Related Disclosures
In March 2024, the SEC issued a final rule that requires disclosure of: (i) financial statement impacts of severe weather events and other natural conditions; (ii) a roll forward of carbon offset and REC balances if material to the Company's plan to achieve climate-related targets or goals; and (iii) material impacts on estimates and assumptions in the financial statements. The rule is effective for TEP for annual periods beginning January 1, 2027 and is to be applied prospectively. In April 2024, the SEC issued an order staying the final rule pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit. TEP cannot predict what, if any, changes in scope or timing may occur as a result of the pending litigation. TEP continues its assessment to prepare for the new rule.
NOTE 2. REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period.
The table below summarizes the PPFAC regulatory asset (liability) balance:
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Beginning of Period $ (31) $ 93 $ 55 $ 124
Deferred Fuel and Purchased Power Costs (1)
95 135 202 258
PPFAC and Base Power Recoveries (120) (140) (313) (294)
End of Period $ (56) $ 88 $ (56) $ 88
(1)Includes costs eligible for recovery through the PPFAC and base power rates.
Transmission Cost Adjustor
The TCA allows for timely recovery or refund of actual costs, net of applicable credits, required to provide transmission services to retail customers. TEP files new TCA rates with the ACC in December each year based on changes in net costs required to provide transmission services to retail customers. New TCA rates take effect in January of each year.
Renewable Energy Standard
The ACC's RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30% of the annual energy requirement. The renewable energy requirement in 2024 is 14% of retail electric sales. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. TEP recovers approved costs of carrying out this plan from retail customers through a RES tariff.
In May 2024, the ACC approved an extension of the 2021 RES implementation with a budget of $66 million until further order of the ACC and an increase to the RES tariff to recover under-collected RES funds totaling $17 million. The ACC also waived for TEP the general requirement that Arizona utilities file an annual RES implementation plan. The approved amount funds: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.
Energy Efficiency Standards
TEP is required to implement cost-effective DSM programs to comply with the ACC's Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs of implementing DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year.
In the 2023 Rate Order, the ACC approved a 2023 energy efficiency implementation plan with a cumulative three-year budget of $72 million, which is collected through the DSM surcharge. In May 2024, the ACC approved refunding over-collected, uncommitted DSM surcharge funds totaling $10 million. The DSM refund credits were applied over the June and July 2024 billing periods.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2020 IRP Energy Efficiency Target
In 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP will report its savings for these years in its first integrated resource plan following 2025 and in TEP's periodic energy efficiency filings.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues based on an estimate of lost retail kWh sales during the period. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below:
($ in millions) Remaining Recovery Period
(years) 		September 30, 2024 December 31, 2023
Regulatory Assets
Pension and Other Postretirement Benefits (Note 8)
Various $ 103 $ 107
Early Generation Retirement Costs Various 50 48
Lost Fixed Cost Recovery 1 31 35
Property Tax Deferrals (1)
1 31 30
Final Mine Reclamation (2)
15 20 6
Derivatives (Note 9)
5 14 26
Transmission Revenue Requirement Balancing Account 1 8 -
Income Taxes Recoverable through Future Rates (3)
Various 5 6
Unamortized Loss on Reacquired Debt Various 4 5
Under-Recovered Fuel and Purchased Energy Costs 1 - 55
Other Regulatory Assets Various 16 12
Total Regulatory Assets 282 330
Less Current Portion 1 89 147
Total Noncurrent Regulatory Assets $ 193 $ 183
Regulatory Liabilities
Income Taxes Payable through Future Rates (3)
Various $ 211 $ 229
Net Cost of Removal (4)
Various 119 130
Renewable Energy Standard Various 84 77
Over-Recovered Fuel and Purchased Energy Costs 1 56 -
Derivatives (Note 9)
5 17 28
Demand Side Management 1 6 9
Deferred Investment Tax Credits Various 5 6
Pension and Other Postretirement Benefits (Note 8)
Various 4 4
Transmission Revenue Requirement Balancing Account 1 - 5
Other Regulatory Liabilities Various - 1
Total Regulatory Liabilities 502 489
Less Current Portion 1 147 93
Total Noncurrent Regulatory Liabilities $ 355 $ 396
(1)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes.
(2)Represents costs associated with TEP's jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022. In March 2024, the San Juan reclamation oversight committee approved a new final mine reclamation study which resulted in a $15 million increase in the final mine reclamation regulatory asset.
(3)Amortized over five years, 10 years, or the lives of the assets.
(4)Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general 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, Transmission Revenue Requirement Balancing
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Account, and Under-Recovered Fuel and Purchased Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.
Roadrunner Reserve I Application for Accounting Order
In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I with an anticipated in-service date in 2025. On October 10, 2024, TEP filed an application with the ACC for an accounting order requesting authorization to defer for future recovery certain costs associated with owning, operating, and maintaining Roadrunner Reserve I, offset by future benefits associated with investment tax credits. TEP cannot predict the timing or outcome of this application.
NOTE 3. REVENUE
DISAGGREGATION OF REVENUES
TEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP's Operating Revenues on the Condensed Consolidated Statements of Income by type of service:
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Retail $ 436 $ 445 $ 1,052 $ 975
Wholesale 72 101 212 291
Other Services 24 25 90 95
Revenues from Contracts with Customers 532 571 1,354 1,361
Alternative Revenues 11 7 30 28
Other 9 15 50 58
Total Operating Revenues $ 552 $ 593 $ 1,434 $ 1,447
NOTE 4. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets:
(in millions) September 30, 2024 December 31, 2023
Retail $ 153 $ 109
Retail, Unbilled 69 57
Retail, Allowance for Credit Losses (13) (12)
Wholesale(1)
31 37
Due from Affiliates (Note 5)
16 7
Other 18 19
Accounts Receivable $ 274 $ 217
(1)Includes $15 million as of September 30, 2024, and $10 million as of December 31, 2023, of receivables related to revenue from derivative instruments.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ALLOWANCE FOR CREDIT LOSSES
TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets:
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Beginning of Period $ (12) $ (9) $ (12) $ (9)
Credit Loss Expense (2) (4) (5) (6)
Write-offs 1 2 4 4
End of Period $ (13) $ (11) $ (13) $ (11)
NOTE 5. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services.
The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets:
(in millions) September 30, 2024 December 31, 2023
Receivables from Related Parties
UNS Electric $ 14 $ 5
UNS Gas 2 2
Total Due from Related Parties $ 16 $ 7
Payables to Related Parties
UNS Energy $ 1 $ 1
UNS Electric 1 1
UNS Gas - 1
Total Due to Related Parties $ 2 $ 3
The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Goods and Services Provided by TEP to Affiliates
Wholesale Revenues, UNS Electric (1)
$ 16 $ 22 $ 19 $ 35
Common Costs, UNS Energy Affiliates (2)
6 6 18 17
Transmission Revenues, UNS Electric (1)
2 2 6 6
Control Area Services, UNS Electric (3)
1 1 2 2
Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (4)
2 2 7 6
Corporate Services, UNS Energy Affiliates (5)
- - 1 1
Capacity Charges, UNS Gas (6)
- - 1 1
Purchased Power, UNS Electric (1)
- - - 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.
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(2)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.
(3)TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement.
(4)Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million and $6 million for the three and nine months ended September 30, 2024 and 2023, respectively.
(5)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
(6)UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.
NOTE 6. DEBT AND CREDIT AGREEMENTS
There have been no significant changes to TEP's debt or credit agreements since December 31, 2023, except as noted below.
DEBT
Issuance and Redemptions
In August 2024, TEP issued and sold $400 million aggregate principal amount of 5.20% senior unsecured notes due September 2034. TEP may redeem the notes prior to June 15, 2034, with a make-whole premium plus accrued interest. On or after June 15, 2034, TEP may redeem the notes at par plus accrued interest.
On November 1, 2024, TEP issued a revocable notice to redeem at par on December 16, 2024, $300 million aggregate principal amount of its 3.05% senior unsecured notes. These notes have a maturity date of March 15, 2025.
CREDIT AGREEMENT
2021 Credit Agreement
In October 2024, the maturity date of TEP's 2021 Credit Agreement was extended one year to October 2027 as permitted by the agreement. The terms of the 2021 Credit Agreement are as follows:
Sub-Limit Swingline(1)
Sub-Limit LOC Weighted Average Interest Rate
Capacity Borrowed Available
Pricing(2)
($ in millions) September 30, 2024
Agreement $ 250 $ 15 $ 50 $ - $ 250 - %
SOFR+ADJ 0.10%+1.050% or ABR+0.050%
(1)ABR pricing would apply to swingline loans.
(2)TEP's pricing through October 15, 2026 may be adjusted based on performance measured using two sustainability targets: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage.
As of November 4, 2024, there was $238 million available under the 2021 Credit Agreement.
NOTE 7. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
There have been no significant changes to TEP's long-term commitments since December 31, 2023, except as noted below.
EPC Agreement
In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. TEP owns and will operate the facility, which will be located in southeast Tucson and have a nominal capacity rating of 200 MW and energy
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
capacity of 800 MWh. Roadrunner Reserve II is expected to be placed in service in the second half of 2026. As of September 30, 2024, TEP has made payments of $74 million in connection with the construction and development of Roadrunner Reserve II.
CONTINGENCIES
Legal Matters
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.
Mine Reclamation at Generation Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation costs are subject to various assumptions, such as: estimations of reclamation costs; timing of when final reclamation will occur; and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP's PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP records its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.
TEP is liable for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP's liability balance related to its share of final mine reclamation costs at Four Corners totaled $3 million and $4 million as of September 30, 2024, and December 31, 2023, respectively, and was recorded in Current Liabilities-Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP expects to accrue an additional $1 million of final mine reclamation costs at Four Corners over the remaining term of the coal supply agreement, which expires in 2031.
TEP ceased operations at San Juan upon expiration of the coal supply agreement in 2022. In March 2024, TEP increased the San Juan final mine reclamation liability by $15 million as a result of a new final mine reclamation study. TEP's remaining final mine reclamation liability at San Juan was $34 million and $25 million as of September 30, 2024, and December 31, 2023, respectively, and was recorded in Current Liabilities-Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2040. See Note 1 for additional information on restricted cash relating to TEP's share of final mine reclamation and decommissioning costs at San Juan.
Performance Guarantees
TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. There is no maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of September 30, 2024, there have been no such payment defaults under either of the participation agreements.
The Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. 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, 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
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.
NOTE 8. EMPLOYEE BENEFIT PLANS
Net periodic benefit cost includes the following components:
Pension Benefits Other Postretirement Benefits
Three Months Ended September 30,
(in millions) 2024 2023 2024 2023
Service Cost $ 4 $ 3 $ 1 $ 1
Non-Service Cost (1)
Interest Cost 6 6 1 1
Expected Return on Plan Assets (8) (8) (1) -
Amortization of Net Loss 1 1 - -
Net Periodic Benefit Cost $ 3 $ 2 $ 1 $ 2
Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Service Cost $ 11 $ 9 $ 3 $ 3
Non-Service Cost (1)
Interest Cost 18 17 3 3
Expected Return on Plan Assets (24) (22) (2) (1)
Amortization of Net Loss 4 3 - -
Net Periodic Benefit Cost $ 9 $ 7 $ 4 $ 5
(1)The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.
CONTRIBUTIONS
TEP contributed $14 million to the pension plans during the nine months ended September 30, 2024. No additional contributions are planned in 2024.
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) September 30, 2024
Assets
Cash Equivalents (1)
$ 55 $ - $ 55
Restricted Cash (1)
27 - 27
Energy Derivative Contracts, Regulatory Recovery (2)
- 27 27
Energy Derivative Contracts, No Regulatory Recovery (2)
- 6 6
Total Assets 82 33 115
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
- (25) (25)
Total Liabilities - (25) (25)
Total Assets (Liabilities), Net $ 82 $ 8 $ 90
(in millions) December 31, 2023
Assets
Restricted Cash (1)
$ 34 $ - $ 34
Energy Derivative Contracts, Regulatory Recovery (2)
- 32 32
Energy Derivative Contracts, No Regulatory Recovery (2)
- 3 3
Total Assets 34 35 69
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
- (30) (30)
Total Liabilities - (30) (30)
Total Assets (Liabilities), Net $ 34 $ 5 $ 39
(1)Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets-Other on the Condensed Consolidated Balance Sheets.
(2)Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:
Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount
Counterparty Netting of Energy Contracts Cash Collateral Received/Posted
(in millions) September 30, 2024
Derivative Assets
Energy Derivative Contracts $ 33 $ 14 $ - $ 19
Derivative Liabilities
Energy Derivative Contracts (25) (14) - (11)
(in millions) December 31, 2023
Derivative Assets
Energy Derivative Contracts $ 35 $ 15 $ - $ 20
Derivative Liabilities
Energy Derivative Contracts (30) (15) - (15)
DERIVATIVE INSTRUMENTS
TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers.
TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or liability in the balance sheet:
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Unrealized Net Gain (Loss) (1)
$ 8 $ - $ - $ (47)
(1)For the nine months ended September 30, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition in the PPFAC plan of administration, TEP must share 10%of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income:
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2024 2023 2024 2023
Operating Revenues $ 3 $ 1 $ 30 $ 18
Derivative Volumes
As of September 30, 2024, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:
September 30, 2024 December 31, 2023
Power Contracts GWh 2,849 1,449
Gas Contracts BBtu 87,681 89,105
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.
TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.
TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to individual contracts.
The fair value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $24 millionas of September 30, 2024, compared with $28 million as of December 31, 2023. TEP hadnocash posted as collateral to provide credit enhancement as of September 30, 2024, and December 31, 2023. TEP would have been required to post $24 millionand $28 millionof collateral if the credit risk contingent features had been triggered on September 30, 2024, and December 31, 2023, respectively. TEP had $15 million and $13 million in outstanding net payable balances for settled positions as of September 30, 2024, and December 31, 2023, respectively.
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.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt:
Fair Value Hierarchy Net Carrying Value Fair Value
(in millions) September 30, 2024 December 31, 2023 September 30, 2024 December 31, 2023
Liabilities
Long-Term Debt, including Current Maturities Level 2 $ 2,794 $ 2,397 $ 2,579 $ 2,127
NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS
Nine Months Ended September 30,
(in millions) 2024 2023
Interest Paid, Net of Amounts Capitalized $ 51 $ 48
NON-CASH TRANSACTIONS
Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:
Nine Months Ended September 30,
(in millions) 2024 2023
Accrued Capital Expenditures (1)
$ 93 $ 32
Renewable Energy Credits 4 4
Asset Retirement Obligations Increase (Decrease) (2) (2)
Net Cost of Removal Increase (Decrease) (2)
(5) 98
(1)In 2024, primarily represents accrued capital expenditures related to Roadrunner Reserve I.
(2)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis explains the results of operations, the financial condition, and the outlook for TEP. It includes the following:
•outlook and strategies;
•factors affecting results of operations;
•results of operations;
•liquidity and capital resources, including capital expenditures, income tax position, and environmental matters;
•critical accounting estimates; and
•new accounting standards issued and not yet adopted.
Management's Discussion and Analysis includes financial information prepared in accordance with GAAP.
Management's Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes in Part I, Item 1 of this Quarterly Report on 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 Quarterly Report on Form 10-Q and Risk Factors in Part 1, Item 1A of our 2023 Annual Report on Form 10-K, and in Part II, Item 1A of this Form Quarterly Report on 10-Q.
References in Management's Discussion and Analysis to "we," "our," and "us" are to TEP.
OUTLOOK AND STRATEGIES
Our financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws, regulations, and policies; and (iv) other regulatory and legislative actions. Our plans and strategies include:
•Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers.
•Continuing our transition to a less carbon-intensive energy portfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. In 2023, we announced our aspirational goal of net zero direct GHG emissions by 2050. The goal keeps us on pace to reduce carbon emissions by 80% compared to 2005 by 2035. The establishment of this additional target reinforces our commitment to decarbonize over the long-term, while preserving customer reliability and affordability. These goals may be impacted by various federal and state energy policies, including policies currently under consideration, and other external factors, including new customer growth.
•Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
Performance - The third quarter of 2024 compared with the third quarter of 2023
We reported net income of $140 million in the third quarter of 2024 compared with net income of $128 million in the third quarter of 2023. The increase of $12 million, or 9%, was primarily due to (net of tax):
•$18 million in higher margin from retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order;
•$3 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of favorable market conditions;
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•$3 million in lower income tax expense primarily due to an increase in tax credits primarily related to Oso Grande PTCs; and
•$3 million in higher AFUDC due to an increase in eligible construction expenditures;
The increase was partially offset by:
•$7 million in higher base operations and maintenance expenses primarily due to an increase in employee wages and benefits expenses, outside services expenses, and higher operations and maintenance expenses at our generation facilities;
•$4 million in higher depreciation expense primarily due to an increase in depreciation rates as approved in the 2023 Rate Order; and
•$3 million in higher interest expense primarily due to the issuance of debt in August 2024.
Performance - The first nine months of 2024 compared with the first nine months of 2023
We reported net income of $262 million in the first nine months of 2024 compared with net income of $223 million in the first nine months of 2023. The increase of $39 million, or 17%, was primarily due to (net of tax):
•$57 million in higher margin from retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order; partially offset by lower LFCR revenues;
•$8 million in higher AFUDC due to an increase in eligible construction expenditures; and
•$6 million in higher margin from wholesale transactions primarily due to an increase in revenues realized from wholesale trading as defined in the PPFAC plan of administration; partially offset by a decrease in long-term wholesale volumes due to less favorable market conditions and the expiration of certain contracts.
The increase was partially offset by:
•$16 million in higher depreciation expense primarily due an increase in depreciation rates as approved in the 2023 Rate Order;
•$10 million in higher base operations and maintenance expenses primarily due to an increase in employee wages and benefits expenses and an increase in outside services expenses; partially offset by lower operations and maintenance expenses at our generation facilities;
•$4 million in lower margin from transmission revenue primarily due to a regulatory decision approving a credit to retail customers for certain transmission revenue beginning in December 2023; partially offset by an increase in TEP's transmission formula rate revenue requirement; and
•$3 million in higher interest expense primarily due to the issuance of debt in August 2024.
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 sales growth and seasonality.
Regulatory Matters
We are subject to comprehensive regulation. The discussion below contains material developments in those matters.
2023 Rate Order
In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:
•a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;
•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% and an average cost of debt of 3.82%; and
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•approval to recover costs of changes in generation resources, including the addition of Oso Grande, in rates.
Roadrunner Reserve I Application for Accounting Order
On October 10, 2024, we filed an application with the ACC for an accounting order requesting authorization to defer for future recovery certain costs associated with owning, operating, and maintaining Roadrunner Reserve I, offset by future benefits associated with investment tax credits. We cannot predict the timing or outcome of this application.
Generation Resource Strategy
Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while reducing reliance on coal-fired generation resources. In 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards a new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps us on pace to reduce our carbon emissions by 80% compared to 2005 by 2035.
As a result of our 2022 All-Source Request for Proposal (ASRFP), we entered into:
•an EPC agreement in September 2023 to develop Roadrunner Reserve I. Roadrunner Reserve I will be a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh with an anticipated in-service date in 2025;
•a renewable PPA in January 2024 with Wilmot Energy Center II (Wilmot II). Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage with energy capacity of 400 MWh, with an anticipated in-service date in 2026; and
•a renewable PPA in April 2024 with Winchester Solar I, LLC (Winchester). Winchester will have 80 MW of solar capacity accompanied by 80 MW of battery storage with energy capacity of 320 MWh, with an anticipated in-service date in 2027.
In December 2023, we issued another ASRFP (2024 ASRFP) based on the resource needs outlined in our 2023 IRP targeting in-service dates of 2026 through 2027. As a result of our 2024 ASRFP, we entered into an EPC agreement in August 2024 to develop Roadrunner Reserve II. Roadrunner Reserve II will be a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh with an anticipated in-service date in the second half of 2026. See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for additional information related to the EPC agreement.
Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations and policies, and, for jointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we expect to exit all ownership interests in coal-fired generation facilities by 2032. We will seek regulatory recovery for amounts, if any, that would not otherwise be recovered as a result of these actions. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings. On October 21, 2024, the ACC acknowledged TEP's IRP and found it to be reasonable and in the public interest.
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 $10 million and $20 million in PTCs related to Oso Grande for the three and nine months ended September 30, 2024, respectively, and $7 million and $16 million, for the three and nine months ended September 30, 2023, respectively. The PTC rate published by the IRS for electricity produced by a qualified facility using wind placed in service prior to 2022 is $0.029 for 2024 and was $0.028 for 2023.
Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, or if any operational constraints exist, the project's electricity generation and associated PTCs may be substantially different compared to prior periods. As of September 1, 2023, Oso Grande is included in rates as part of the 2023 Rate Order.
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Sales Growth and Seasonality
Our average retail sales growth has remained relatively flat over the past three years. Recently, we have experienced unprecedented interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet above what is reflected in our 2023 IRP, as well as higher transmission and distribution infrastructure investments. We are analyzing the requests and cannot predict the quantity or timing of the energy demand that may result from the current interest received.
Weather Patterns
Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our retail sales are highest in the second and third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year, due to mild winter weather in our retail service territory. Our operating costs are generally consistent throughout the year which produces higher operating income in the second and third quarter and lower operating income in the first and fourth quarter. As a result, seasonal fluctuations affect the comparability of our results of operations.
Interest Rates
See Part II, Item 7A in our 2023 Annual Report on Form 10-K and Part I, Item 3 of this Quarterly Report on Form 10-Q for information regarding interest rate risk and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of our results of operations that do not have a significant impact on net income include:
•Cost Recovery Mechanisms- We record operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchased power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, the RES tariff, and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for additional information on cost recovery mechanisms.
•Short-Term Wholesale Sales- Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC mechanism.
•Springerville Units 3 and 4- Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.
The following discussion provides the significant items that affected our results of operations in the third quarter and first nine months of 2024 compared with the same period in 2023 presented on a pre-tax basis.
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Operating Revenues
The following table provides a disaggregation of Operating Revenues:
Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30, Increase (Decrease)
(in millions) 2024 2023 Percent 2024 2023 Percent
Operating Revenues
Retail $ 436 $ 445 (2.0) % $ 1,052 $ 975 7.9 %
Wholesale, Short-Term (1)
45 73 (38.4) % 156 209 (25.4) %
Wholesale, Long-Term 13 18 (27.8) % 44 60 (26.7) %
Transmission 15 14 7.1 % 41 43 (4.7) %
Springerville Units 3 and 4 Participant Billings 21 21 - % 80 84 (4.8) %
Other 22 22 - % 61 76 (19.7) %
Total Operating Revenues $ 552 $ 593 (6.9) % $ 1,434 $ 1,447 (0.9) %
(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 $552 million in the third quarter of 2024 compared with $593 million in the same period for 2023. The decrease of $41 million, or 7%, was primarily due to:
•$28 million in lower short-term wholesale revenues primarily due to a decrease in price and volume;
•$9 million in lower retail revenue primarily due to (i) lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate; and (ii) lower usage as a result of less favorable weather; partially offset by an increase in rates as approved in the 2023 Rate Order; and
•$5 million in lower long-term wholesale revenues primarily due to a decrease in volumes due to less favorable market conditions and the expiration of certain contracts.
We reported Operating Revenues of $1,434 million for the first nine months of 2024 compared with $1,447 million in the same period for 2023. The decrease of $13 million, or 1%, was primarily due to:
•$53 million in lower short-term wholesale revenues primarily due to a decrease in price; partially offset by an increase in revenue realized from wholesale trading as defined in the PPFAC plan of administration;
•$16 million in lower long-term wholesale revenues primarily due to a decrease in volume due to less favorable market conditions and the expiration of certain contracts;
•$15 million in lower other revenue primarily due to the expiration of an asset management agreement and lower alternative revenues; and
•$4 million in lower Springerville Units 3 and 4 participant billings primarily due to higher reimbursable planned outage costs in 2023.
The decrease was partially offset by $77 million in higher retail revenues primarily due to (i) an increase in rates as approved in the 2023 Rate Order; and (ii) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate.
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The following table provides key statistics impacting Operating Revenues:
Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30, Increase (Decrease)
(kWh in millions) 2024 2023 Percent 2024 2023 Percent
Electric Sales (kWh) (1)
Retail Sales 2,988 3,053 (2.1) % 7,013 7,037 (0.3) %
Wholesale, Long-Term 226 300 (24.7) % 740 1,031 (28.2) %
Wholesale, Short-Term 1,162 1,375 (15.5) % 3,940 3,416 15.3 %
Total Electric Sales 4,376 4,728 (7.4) % 11,693 11,484 1.8 %
Average Revenue per kWh (2)
Retail 14.60 14.55 0.3 % 15.00 13.85 8.3 %
Wholesale, Long-Term 6.08 6.32 (3.8) % 6.00 5.87 2.2 %
Wholesale, Short-Term 3.87 5.18 (25.3) % 3.26 5.58 (41.6) %
Total Retail Customers (3)
451,072 445,952 1.1 %
(1)These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.
(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
(3)This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining and non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.
Operating Expenses
Fuel and Purchased Power Expense
We reported Fuel and Purchased Power expense of $188 million in the third quarter of 2024 compared with $243 million in the same period for 2023. The decrease of $55 million, or 23%, was primarily due to:
•$47 million in lower Purchased Power expenses primarily due to a decrease in price and volume;
•$15 million in lower Fuel expenses primarily due to a decrease in natural gas prices; partially offset by: (i) higher realized losses on natural gas swaps; (ii) an increase in coal prices; and (iii) an increase in Gas-Fired Generation volumes; and
•$11 million in lower Transmission and Other PPFAC Recoverable Costs primarily due to a decrease in transmission service expenses.
The decrease was partially offset by an $18 million increase in PPFAC Recovery Treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; partially offset by a decrease in PPFAC cost recoveries.
We reported Fuel and Purchased Power expense of $511 million for the first nine months of 2024 compared with $582 million for the same period for 2023. The decrease of $71 million, or 12%, was primarily due to:
•$77 million in lower Purchased Power expenses primarily due to a decrease in price and volume;
•$39 million in lower Fuel expenses primarily due to a decrease in natural gas prices; partially offset by: (i) higher realized losses on natural gas swaps; (ii) an increase in coal prices; and (iii) an increase in Gas-Fired Generation volumes; and
•$9 million in lower Transmission and Other PPFAC Recoverable Costs primarily due to a decrease in transmission service expenses.
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The decrease was partially offset by a $55 million increase in PPFAC Recovery Treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery and an increase in PPFAC cost recoveries.
The following table provides key statistics impacting Fuel and Purchased Power:
Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30, Increase (Decrease)
(kWh in millions) 2024 2023 Percent 2024 2023 Percent
Sources of Energy
Coal-Fired Generation 933 1,099 (15.1) % 2,512 2,674 (6.1) %
Gas-Fired Generation 2,696 2,373 13.6 % 6,686 5,788 15.5 %
Utility-Owned Renewable Generation 181 148 22.3 % 595 571 4.2 %
Total Generation 3,810 3,620 5.2 % 9,793 9,033 8.4 %
Purchased Power, Non-Renewable 423 1,040 (59.3) % 1,276 1,830 (30.3) %
Purchased Power, Renewable 326 311 4.8 % 1,047 1,085 (3.5) %
Total Generation and Purchased Power (1)
4,559 4,971 (8.3) % 12,116 11,948 1.4 %
(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal (3)
4.02 3.06 31.4 % 4.42 3.04 45.4 %
Natural Gas (4)
1.97 2.70 (27.0) % 2.13 3.48 (38.8) %
Average Cost of Purchased Power (5)
Purchased Power, Non-Renewable 7.11 8.49 (16.3) % 3.09 7.15 (56.8) %
Purchased Power, Renewable 6.82 6.79 0.4 % 6.91 6.73 2.7 %
(1)This number represents the kWh generated from our generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.
(2)This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation facilities.
(3)In 2024, coal prices increased due to the execution of a coal supply agreement for Springerville Units 1 and 2 through 2031.
(4)Includes realized gains and losses from hedging activity.
(5)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 $106 million in the third quarter of 2024 compared with $104 million in the same period for 2023. The increase of $2 million, or 2%, was primarily due to:
•$3 million in higher employee wages and benefits expenses;
•$3 million in higher outside services expenses; and
•$2 million in higher operations and maintenance expenses at our generation facilities.
The increase was partially offset by:
•$4 million in lower RES and DSM expenses; and
•$2 million in lower reimbursable maintenance expense related to Springerville Units 3 and 4 primarily due to higher planned outage costs in 2023.
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We reported Operations and Maintenance expense of $330 million for the first nine months of 2024 compared with $332 million for the same period for 2023. The decrease of $2 million, or 1%, was primarily due to:
•$7 million in lower RES and DSM expenses;
•$6 million in lower reimbursable maintenance expense related to Springerville Units 3 and 4 primarily due to higher planned outage costs in 2023; and
•$2 million in lower operations and maintenance expenses at our generation facilities.
The decrease was partially offset by:
•$7 million in higher employee wages and benefits expenses; and
•$6 million in higher outside services expenses.
Depreciation and Amortization Expense
We reported Depreciation and Amortization expense of $64 million in the third quarter of 2024 compared with $59 million in the same period for 2023. The increase of $5 million, or 8%, was primarily due to an increase in depreciation rates as approved in the 2023 Rate Order.
We reported Depreciation and Amortization expense of $192 million for the first nine months of 2024 compared with $173 million for the same period for 2023. The increase of $19 million, or 11%, was primarily due to an increase in depreciation rates as approved in the 2023 Rate Order.
Other Income (Expense)
We reported Other Expense of $15 million in the third quarter of 2024 compared with $18 million in the same period for 2023. The decrease of $3 million, or 17%, was primarily due to
•$4 million in higher AFUDC due to an increase in eligible construction expenditures; and
•$3 million increase in the value of investments used to support certain post-employment benefits as a result of favorable market conditions.
The decrease was partially offset by $3 million in higher interest expense due to the issuance of debt in August 2024.
We reported Other Expense of $46 million for the first nine months of 2024 compared with $50 million for the same period for 2023. The decrease of $4 million, or 8%, was primarily due to $10 million in higher AFUDC due to an increase in eligible construction expenditures; partially offset by $4 million in lower interest income on under-recovered PPFAC balances.
Income Tax Expense
We reported Income Tax Expense of $21 million in the third quarter of 2024 compared with $23 million in the same period for 2023. The decrease of $2 million, or 9%, was primarily due to $3 million in higher tax credits related to Oso Grande PTCs.
We reported Income Tax Expense of $39 million for the first nine months of 2024 compared with $36 million for the same period for 2023. The increase of $3 million, or 8%, was primarily due to $11 million in higher tax expense due to an increase in taxable earnings; the increase was partially offset by $4 million in higher tax credits related to Oso Grande PTCs.
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LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Any extended period of economic disruption could affect our business, financial condition, and access to sources of liquidity. Cash flows vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to our summer peaking load. We face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. We use our revolving credit as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.
Available Liquidity
(in millions) September 30, 2024
Cash and Cash Equivalents $ 354
Amount Available under Revolving Credit Agreement(1)
250
Total Liquidity $ 604
(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 an original maturity date of October 2026. In October 2024, the maturity date was extended one year to October 2027. 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 Quarterly Report on Form 10-Q for additional information regarding our market risks.
Summary of Cash Flows
The table below presents net cash provided by (used for) operating, investing, and financing activities:
Nine Months Ended September 30, Increase (Decrease)
(in millions) 2024 2023 Percent
Operating Activities (1)
$ 530 $ 428 23.8 %
Investing Activities (1)
(505) (388) 30.2 %
Financing Activities (1)
313 80 291.3 %
Net Increase (Decrease) 338 120 181.7 %
Beginning of Period 43 51 (15.7) %
End of Period $ 381 $ 171 122.8 %
(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 increased by $102 million in the first nine months of 2024 compared with the same period in 2023. The increase was primarily due to: (i) higher retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order; and (ii) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate. The increase was partially offset by changes in working capital associated with wholesale sales.
Investing Activities
Net cash flows used for investing activities increased by $117 million in the first nine months of 2024 compared with the same period in 2023 primarily due to an increase in cash paid for capital expenditures.
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Financing Activities
Net cash flows provided by financing activities increased by $233 million in the first nine months of 2024 compared with the same period in 2023 primarily due to no redemptions of long-term debt in 2024; partially offset by an increase in dividends declared and paid to UNS Energy.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of September 30, 2024, our short-term investments were deposited in insured cash sweep, interest-bearing checking, and money market accounts.
Access to Credit
We have access to working capital through our credit agreement with lenders. Amounts borrowed from the 2021 Credit Agreement are used for working capital and other general corporate purposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of November 4, 2024, there was $238 million available under the 2021 Credit Agreement.
See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q and Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2023 Annual Report on Form 10-K for additional information regarding our 2021 Credit Agreement.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings. In December 2020, the ACC issued an order granting our financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate. In May 2022, we filed with the SEC an automatic shelf registration statement on Form S-3 which expires in May 2025.
We have, from time to time, refinanced or repurchased portions of our outstanding debt before scheduled maturity. Depending on market conditions, we may refinance or repurchase additional outstanding debt before its scheduled maturity.
In August 2024, we issued and sold $400 million aggregate principal amount of 5.20% senior unsecured notes due September 2034. We plan to use the net proceeds to repay debt and for general corporate purposes.
As of September 30, 2024, we had $300 million of long-term debt maturing on March 15, 2025, recorded in Current Maturities of Long-Term Debt, Net on the Condensed Consolidated Balance Sheets. On November 1, 2024, we issued a revocable notice to redeem at par on December 16, 2024, $300 million aggregate principal amount of our 3.05% senior unsecured notes.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2024, credit ratings from S&P Global Ratings and Moody's Investors Service for our senior unsecured debt were A- (negative) and A3 (stable), respectively.
Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold our securities. Each rating should be evaluated independently of any other ratings.
The 2021 Credit Agreement contains pricing based on our credit ratings. A change in our credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.
Debt Covenants
Under certain agreements, should we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2024, we were in compliance with these covenants.
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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 from UNS Energy in the third quarter or first nine months of 2024. We received no equity contributions from UNS Energy in the third quarter of 2023 and received an equity contribution of $6 million in the first nine months of 2023.
Dividends Declared and Paid to Parent
We declared and paid $85 million in dividends to UNS Energy in the third quarter and first nine months of 2024. We did not declare or pay dividends to UNS Energy in the third quarter of 2023, and we declared and paid $55 million in dividends to UNS Energy in the first nine months of 2023.
Master Trading Agreements
We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of September 30, 2024, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.
Capital Expenditures
Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. We prioritize capital projects to mitigate supply chain risk particularly in view of heightened geopolitical instability and global supply chain challenges. Capital expenditures for the first nine months of 2024 totaled $460 million and included: (i) investments in distribution and transmission assets, including payments for the construction of the Vail to Tortolita 230kV transmission line; and (ii) investments in Roadrunner Reserve I and II. Capital expenditures for the first nine months of 2023 totaled $345 million and included: (i) investments in distribution and transmission assets, including payments for the construction of the Vail to Tortolita 230kV transmission line; and (ii) investments in Roadrunner Reserve I.
Our forecasted capital expenditures presented below exclude amounts for AFUDC equity and other non-cash items:
Years Ended December 31,
(in millions) 2024 2025 2026 2027 2028
Generation Facilities:
New Energy Resources(1)
$ 318 $ 240 $ 43 $ 124 $ 134
Other Generation Facilities(2)
68 116 234 285 300
Total Generation Facilities 386 356 277 409 434
Transmission and Distribution (3)
317 361 304 272 234
General and Other (4)
76 73 80 61 63
Total Capital Expenditures $ 779 $ 790 $ 661 $ 742 $ 731
(1)Includes investments in renewable energy, Roadrunner Reserve I and II in alignment with our long-term strategy of transitioning to a less carbon intensive energy portfolio. In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for additional information on the EPC agreement.
(2)Includes investments in existing facilities, including upgrades and ongoing maintenance to ensure reliability.
(3)Investments in transmission capacity and distribution system reliability.
(4)Includes costs for information technology, fleet, facilities, and communication equipment.
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These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, including inflationary pressures, construction schedules, labor shortages and/or labor strikes, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, new or changing commitments, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt, other borrowings, or equity contributions.
Income Tax Position
Under the terms of the tax sharing agreement with UNS Energy, we made $9 million in tax sharing payments for the first nine months of 2024 and received $1 million in tax sharing payments for the first nine months of 2023. Future tax payments or receipts are subject to change and are not expected to have a significant impact on our operating cash flows.
Environmental Matters
The EPA has the authority to regulate the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. We expect recovery of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.
Regional Haze Regulations
The EPA's Regional Haze rule requires emission reductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas (Regional Haze). The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a SIP and must review and submit revisions to the SIP on a periodic basis.
In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The ADEQ began to develop a control strategy with a focus on making reasonable progress toward the national visibility goal. In July 2019, we were notified by the ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluations. We conducted the potential emissions controls evaluations, commonly referred to as the four factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP.
In May 2024, the EPA published a proposed rule to partially approve and partially disapprove the ADEQ's Regional Haze SIP revision. The EPA proposed to disapprove ADEQ's control strategy in the revised SIP, which relies, in part, on the compliance measures for Sundt Unit 3 and Springerville Units 1 and 2. The EPA also requested further evaluation of Sundt Unit 4. In the event that the EPA finalizes the rule as proposed, the ADEQ has the opportunity to respond to the EPA and cure the deficiencies. In the alternative, the EPA will issue a federal implementation plan (FIP) that may contain EPA-required compliance measures for these units at Sundt and Springerville. The EPA must take final action on Arizona's Regional Haze SIP Revision by March 30, 2025, per consent decree entered in the U.S. District Court for the District of Columbia.
The public comment period for the proposal closed in July 2024. We cannot predict the outcome of this matter.
Greenhouse Gas Regulation
On May 9, 2024, the EPA published final rules to regulate GHG emissions from two categories of fossil-based electric generating units (EGUs): (i) existing steam units (including coal- and natural gas-fired); and (ii) new natural gas fired turbines. The EPA did not take final action on existing natural gas-fired combustion turbines but has indicated that it plans to issue a supplemental proposal to address these units by the end of 2024.
The final rule established:
•Emission guidelines for existing coal-fired steam EGUs, which are subcategorized based on federally enforceable retirement dates. These emission guidelines affect Springerville Units 1 and 2, as well as Four Corners Units 4 and 5;
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•Emission guidelines for existing natural gas- and oil-fired steam EGUs aligned with routine methods of operation and maintenance, which are subcategorized based on the annual capacity factor of each unit beginning January 1, 2030. These emission guidelines affect Sundt Units 3 and 4.
•A requirement for states to establish standards of performance that align with the emission guidelines, in the form of emission limits. States must submit these standards of performance to the EPA for approval in the form of a state plan, which is due to the EPA in May 2026; and
•New source performance standards for new stationary natural gas-fired combustion turbines, which are subcategorized based on the annual capacity factor for each unit. For base load units (i.e., units with an annual capacity factor greater than 40%), the EPA established a two-phased performance standard. For phase 1, new base load units must initially meet performance standards based on the use of highly efficient combined cycle generation with the best operating and maintenance practices. For phase 2, the final rule requires that such base load units achieve emissions reductions aligned with a 90% carbon capture and sequestration (CCS) rate beginning on January 1, 2032.
We are analyzing the EPA's final rule. Various legal challenges to the final rule are pending before the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this matter.
Coal Combustion Residuals Regulation
In April 2015, the EPA published final rules effective October 2015 (2015 CCR Rule), which established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The 2015 CCR Rule provides for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at Springerville. Arizona Public Service Company, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility. SRP, the former operator of Navajo, is completing closure activities at the facility's CCR landfill. With regards to future corrective actions at Four Corners to comply with the 2015 CCR Rule, our share of costs to complete any corrective actions, or to gather and perform remedial evaluations on groundwater at Units 4 and 5, is not expected to have a significant impact on our financial position, results of operations, or cash flows
On May 8, 2024, the EPA published the final Legacy CCR Surface Impoundments Rule that expands the scope of the 2015 CCR Rule to address the impacts from historical CCR management and placement activities that would have ceased prior to 2015. The EPA rule establishes two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCR Management Units (CCRMUs) which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. A CCRMU includes not only historically closed landfills and surface impoundments, but also prior applications of CCR on land, such as for structural fill. The final rule also establishes assessment, groundwater monitoring, closure, and post-closure requirements for legacy CCR impoundments and CCRMUs.
We are analyzing the EPA's final rule for potential impacts to our operations. We anticipate that CCRMUs will be identified at Springerville and Four Corners. The number, location, and size of these CCRMUs will be assessed in accordance with the compliance schedule outlined in the EPA's final rule; therefore, associated compliance costs cannot be accurately predicted at this time. SRP identified CCRMUs at Navajo. Our estimated cost to comply with the EPA's final rule at Navajo is not expected to have a significant impact on our financial position, results of operations, or cash flows.
Good Neighbor Federal Implementation Plan
In September 2018, the ADEQ submitted to the EPA the Arizona State Implementation Plan Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone National Ambient Air Quality Standard (NAAQS). In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.
In March 2023, the EPA released its final FIP to address the interstate transport of ozone (Good Neighbor FIP). The Good Neighbor FIP was published in the Federal Register in June 2023, with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOxemission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.
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In February 2024, the EPA published a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona's inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOxemission reduction requirements. The EPA must take final action on Arizona's Ozone Transport SIP Revision by November 26, 2024, per consent decree entered in the U.S. District Court for the Northern District of California.
On June 27, 2024, the U.S. Supreme Court granted a stay of the Good Neighbor FIP pending the disposition of the petitions for review of the Good Neighbor FIP currently pending in the U.S. Court of Appeals for the District of Columbia Circuit. On September 12, 2024, the U.S Court of Appeals for the District of Columbia Circuit Court granted the EPA's request to remand the Good Neighbor FIP rulemaking record and further respond to comments related to the issues addressed in the U.S. Supreme Court's stay. We 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 nine months ended September 30, 2024, to the items that we disclosed as our critical accounting estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2023 Annual Report on Form 10-K.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. TEP can enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows but are not expected to affect earnings due to expected recovery through regulatory mechanisms.
There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2023 Annual Report on Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
TEP's Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP's evaluation of its disclosure controls and procedures as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP's periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP's Chief Executive Officer and Chief Financial Officer concluded that TEP's disclosure controls and procedures were effective as of September 30, 2024. There was no change in TEP's internal control over financial reporting during the quarter ended September 30, 2024, that materially affected, or is reasonably likely to materially affect, TEP's internal control over financial reporting.
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PART II
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal proceedings affecting TEP, refer to Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Pursuant to Item 103 of Regulation S-K under the Exchange Act, TEP is required to disclose certain information about environmental proceedings to which a governmental authority is a party if TEP reasonably believes such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. TEP has elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.
ITEM 1A. RISK FACTORS
The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2023 Annual Report on Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2023 Annual Report on Form 10-K.
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ITEM 6. EXHIBITS
EXHIBIT INDEX
Exhibit No. Description
Officer's Certificate, dated August 9, 2024, authorizing 5.20% Senior Notes due 2034 (Form 8-K dated August 9, 2024, File No. 1-5924 - Exhibit 4.1).
*31(a)
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Susan M. Gray.
*31(b)
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Frank P. Marino.
**32
Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH XBRL Taxonomy Extension Schema Document.
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB XBRL Taxonomy Extension Label Linkbase Document.
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF XBRL Taxonomy Extension Definition Linkbase Document.
104
The cover page from TEP's Quarterly Report on Form 10-Q for the quarter ended September 30, 2024, formatted in Inline XBRL and contained in Exhibit 101.
* Filed herewith.
** Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
TUCSON ELECTRIC POWER COMPANY
(Registrant)
Date: November 4, 2024 /s/ Frank P. Marino
Frank P. Marino
Sr. Vice President, Chief Financial Officer, and Director
(Principal Financial Officer)
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