EDGAR 10-K Filing

Company CIK: 100122
Filing Year: 2024
Filename: 100122_10-K_2024_0000100122-24-000002.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson metropolitan area for 131 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 447,000 retail customers. TEP’s service territory covers 1,155 square miles and includes a population of over one million people in Pima County, as well as parts of Cochise County. TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP is subject to comprehensive state and federal regulation. The regulated electric utility operation is TEP's only segment.
TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis, whose principal executive offices are located in St. John's, Newfoundland and Labrador, Canada.
Regulated Utility Operations
TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for natural gas, coal-fired, renewable generation resources, and a battery energy storage system to provide electricity. This electricity, together with electricity purchased in the wholesale market, is delivered over transmission lines which are part of the Western Interconnection, a regional grid in the United States. The electricity is then transformed to lower voltages and delivered to customers through TEP's distribution system.
FERC Regulation and Rates
The FERC regulates portions of TEP's utility accounting practices and rates, including rates and services for electric transmission and wholesale power sales in interstate commerce. The FERC establishes rates that allow a utility to recover transmission related costs.
FERC Rates
TEP has a forward-looking OATT formula rate, which updates annually and allows for timely recovery of transmission-related costs and an opportunity to earn a reasonable return on its investment. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
ACC Regulation and Rates
TEP operates under a certificate of public convenience and necessity as regulated by the ACC, under which TEP is obligated to provide electricity service to customers within its service territory. The ACC establishes rates that are designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment.
The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect TEP's business decisions and accounting practices.
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. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. In 2023, the percentage of TEP's retail kWh sales attributable to the RES was approximately 22%, exceeding the 2023 requirement of 13%.
Energy Efficiency Standard
Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. TEP achieved the ACC's cumulative annual targeted retail kWh savings in 2020. As of December 31, 2023, TEP’s cumulative annual energy savings was approximately 27%.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding RES and EE Standards.
ACC Rates
Retail Rates are generally established in rate case proceedings. TEP's last rate case proceeding was finalized in 2023. As a result of past regulatory decisions, TEP has cost recovery mechanisms that allow for more timely recovery of certain costs between rate case proceedings. These mechanisms are generally reset annually through separate filings with the ACC. TEP's cost recovery mechanisms include:
•PPFAC - a usage-based charge or credit that reflects changes in energy costs that are not recovered through base rates established in a rate case.
•RES tariff - a usage-based charge that recovers the cost of complying with the RES.
•DSM - a usage-based charge that recovers the cost of complying with the EE Standards.
•LFCR - a usage-based charge that partially offsets the revenue TEP loses when customers reduce their bills as a result of energy efficiency programs and DG system installations.
•ECA - a usage-based charge that recovers certain costs incurred at TEP's generation facilities to comply with environmental regulations.
•TEAM - a usage-based charge or credit used to pass through certain income tax effects to retail customers, which may include impacts of post-test year tax law changes.
•TCA - a usage-based charge or credit that allows TEP to reflect changes in costs related to investments and expenses included in TEP's FERC OATT formula rate.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations and Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on TEP's 2023 Rate Order and cost recovery mechanisms.
Customers
Electricity sold to retail and wholesale customers by class of customer and the average number of retail customers over the last five years were as follows:
(sales in GWh) 2023 2022 2021 2020 2019
Electric Sales
Residential 3,967 27 % 3,879 27 % 3,820 25 % 4,170 28 % 3,698 22 %
Commercial 1,948 13 % 1,917 13 % 1,939 13 % 2,005 14 % 2,077 13 %
Industrial, non-Mining 1,944 13 % 1,946 13 % 1,893 12 % 1,834 12 % 1,896 12 %
Industrial, Mining 1,080 7 % 1,053 7 % 1,050 7 % 1,086 7 % 1,057 6 %
Other 15 - % 15 - % 16 - % 16 - % 16 - %
Total Retail Sales 8,954 60 % 8,810 60 % 8,718 57 % 9,111 61 % 8,744 53 %
Wholesale, Long-Term (1)
1,314 9 % 1,659 11 % 837 6 % 508 4 % 490 3 %
Wholesale, Short-Term (2)
4,486 31 % 4,203 29 % 5,643 37 % 5,279 35 % 7,257 44 %
Total Electric Sales 14,754 100 % 14,672 100 % 15,198 100 % 14,898 100 % 16,491 100 %
Average Number of Retail Customers
Residential 404,616 91 % 400,751 91 % 396,562 90 % 391,953 90 % 387,409 90 %
Commercial 39,702 9 % 39,547 9 % 39,395 9 % 39,096 9 % 38,838 9 %
Industrial, non-Mining 570 - % 574 - % 523 - % 491 - % 503 - %
Industrial, Mining 4 - % 4 - % 4 - % 4 - % 4 - %
Other 1,870 - % 1,875 - % 1,873 1 % 1,877 1 % 1,872 1 %
Total Retail Customers 446,762 100 % 442,751 100 % 438,357 100 % 433,421 100 % 428,626 100 %
(1)Increase prior to 2023 primarily due to favorable market conditions. Decrease in 2023 due to a reduction in sales to certain long-term wholesale customers.
(2)Decrease since 2019 primarily due to the retirement of coal-fired generation and Gila River Unit 2 replacing the generation to serve retail load in 2019.
Retail Customers
TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, healthcare, education, military bases, and governmental entities. TEP’s retail sales are influenced by several factors including economic conditions, seasonal weather patterns, DSM initiatives and the increasing use of energy-efficient products, and customer-sited DG.
Local, regional, and national economic factors impact the growth in the number of customers in TEP’s service territory. In each of the past five years, TEP’s average number of retail customers increased by approximately 1%. TEP expects the number of retail customers to increase at a rate of approximately 1% in 2024 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 2023 was 8,954 GWh, which is an increase of 2% from 2019 levels. During the past five years, increased sales volumes due to warmer weather and customer growth have been tempered by state requirements to promote energy efficiency and DG.
In 2020, due to changes in consumer and business behavior in response to the COVID-19 pandemic, there was a decrease in energy usage by commercial and industrial customers. Due to stay-at-home orders and the adoption of work from home practices, along with record heat in 2020, there was an offsetting increase in energy usage by residential customers starting in the second quarter of 2020. In 2021, usage began to return to pre-COVID-19 pandemic patterns, remaining consistent through 2023.
Wholesale Customers
TEP’s utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale sales transactions are made on both a firm and interruptible basis. A firm contract requires TEP to supply power on demand (except
under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions.
Generally, TEP commits to future sales based on expected generation capability, forward prices, and generation costs using a diversified portfolio approach to provide a balance between long-term, mid-term, and spot power sales.
Long-Term Wholesale Sales
Contracts for long-term wholesale sales cover periods of one year or greater. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers.
TEP's primary long-term wholesale sale contracts are presented in the table below:
Counterparty Contracts Expire December 31,
Navajo Tribal Utility Authority 2024
TRICO Electric Cooperative 2024
Navopache Electric Cooperative 2041
Short-Term Wholesale Sales
Certain contracts for short-term wholesale sales cover periods of less than one year and obligate TEP to sell capacity or power at a fixed price. TEP also engages in short-term wholesale sales by selling power in the daily or hourly markets at fluctuating spot market prices and making other non-firm power sales. The majority of TEP's revenues from short-term wholesale sales are passed through to TEP’s retail customers offsetting fuel and purchased power costs. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices.
In 2022, TEP began to participate in the EIM, a voluntary, real-time energy market operated by the California Independent System Operator. TEP continues to expect that its participation in the EIM: (i) reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allows for more effective integration of renewables; and (iii) enhances reliability through improved system utilization and responsiveness.
Competition
Retail Customers
TEP is the primary electric service provider to retail customers within its service territory and operates under a certificate of public convenience and necessity as regulated by the ACC.
Wholesale Customers
TEP engages in long-term wholesale sales to optimize its generation resources. As a result of its wholesale power activity, TEP competes with other utilities, power marketers, and independent power producers in wholesale markets.
Generation Facilities
As of December 31, 2023, TEP had 3,101 MW of nominal generation capacity, as set forth in the following table. Nominal rating is based on current unit design basis net output, measured in AC:
Unit Date Capacity Operating TEP’s Share
Generation Source No. Location In Service (MW) Agent % (MW)
Natural Gas
Gila River (1)
2 Gila Bend, AZ 2003 607 SRP 100 607
Gila River (1)
3 Gila Bend, AZ 2003 573 SRP 75.0 430
Luna 1 Deming, NM 2006 555 PNM 33.3 185
Sundt 3 Tucson, AZ 1962 104 TEP 100 104
Sundt 4 Tucson, AZ 1967 156 TEP 100 156
Sundt Reciprocating Internal Combustion Engine 1-10 Tucson, AZ 2019-2020 188 TEP 100 188
Sundt Internal Combustion Turbines Tucson, AZ 1972-1973 50 TEP 100 50
DeMoss Petrie (2)
Tucson, AZ 2001 75 TEP 100 75
North Loop Tucson, AZ 2001 96 TEP 100 96
Coal
Springerville 1 Springerville, AZ 1985 387 TEP 100 387
Springerville (3)
2 Springerville, AZ 1990 406 TEP 100 406
Four Corners 4 Farmington, NM 1969 785 APS 7.0 55
Four Corners 5 Farmington, NM 1970 785 APS 7.0 55
Renewables
Utility-Owned Renewables Various 2002-2023 307 TEP 100 307
Total Capacity 3,101
(1)In 2023, Gila River Unit 2 and Unit 3 turbine upgrades increased capacity by 57 MW and 23 MW, respectively, for a total nominal capacity of 607 MW and 573 MW, respectively.
(2)DeMoss Petrie is accompanied by 10 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(3)Springerville Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.
Springerville Units 3 and 4 are each approximately 400 MW coal-fired generation facilities that are operated, but not owned, by TEP. These facilities are located at the same site as Springerville Units 1 and 2. Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, compensate TEP for operating the facilities. Tri-State pays an allocated portion of the fixed costs related to the Springerville Common Facilities and Springerville Coal Handling Facilities. SRP owns 17.05% of the Springerville Coal Handling Facilities and 14% of the Springerville Common Facilities.
Utility-Owned Renewables
As of December 31, 2023, TEP owned 57 MW of PV solar generation capacity and 250 MW of wind generation capacity, measured in AC. The following table presents TEP's owned renewable generation resources:
Generation Source Location Date/Projected Date
in Service In Service
Capacity (MW) Under Development
Capacity (MW)
Solar
Fort Huachuca Phase I & II (1)
Sierra Vista, AZ 2014-2017 18
Raptor Ridge Tucson, AZ 2022 13
Springerville Solar Springerville, AZ 2002-2014 13
UASTP Phase I & II (2)
Tucson, AZ 2010-2011 6
Solon Prairie Fire (2)
Tucson, AZ 2012 5
Small Solar Generation (<5MW) Tucson, AZ 2012-2023 2 3
Wind
Oso Grande (3)
Chaves County, NM 2021 250
Battery Storage
Roadrunner Reserve I (4)
Tucson, AZ 2025 200
Total Capacity 307 203
(1)TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.
(2)UASTP Phase I & II and Solon Prairie Fire are located on properties held under land easements and leases.
(3)Oso Grande is located on properties held under leases.
(4)Expected to be placed in service in the second half of 2025.
Renewable Power Purchase Agreements
As of December 31, 2023, TEP had renewable PPAs for 256 MW from solar resources and 179 MW from wind resources as presented in the table below. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date. The following table's capacity is measured in AC:
Generation Source Location Date/Projected Date
in Service In Service
Capacity (MW) Under Development
Capacity (MW)
Solar
Wilmot Solar (1)
Sahuarita, AZ 2021 100
Red Horse Willcox, AZ 2015 41
Avalon I Sahuarita, AZ 2014 29
Avra Valley Marana, AZ 2012 25
Picture Rocks Marana, AZ 2012 20
Avalon II Sahuarita, AZ 2016 16
Valencia Tucson, AZ 2013 10
Gato Montes Tucson, AZ 2012 5
E.On Tech Park Tucson, AZ 2012 5
Small PPAs (<5MW) (2)
Various Various 5
Babacomari North (3)
Cochise County, AZ 2025 160
Wind
Borderlands Wind
Catron County, NM 2021 99
Macho Springs Deming, NM 2011 50
Red Horse Wind Willcox, AZ 2015 30
Total Capacity (4)
435 160
(1)Wilmot Solar is accompanied by 30 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(2)Includes Iron Horse which has 2 MW of capacity accompanied by 10 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(3)In October 2023, Babacomari North and South contracts were restated and are now represented solely as Babacomari North.
(4)In January 2024, a renewable power purchase agreement was executed with Wilmot Energy Center II (Wilmot II) with an anticipated in service date of 2026. Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage.
Purchased Power
TEP purchases power from other utilities and power marketers. TEP may enter into contracts to purchase: (i) power under long-term contracts to serve retail load and long-term wholesale contracts; (ii) capacity or power during periods of planned outages or for peak summer load conditions; and (iii) power for resale to certain wholesale customers under load and resource management agreements. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to purchased power commitments.
TEP typically uses its generation, supplemented by purchased power, to meet the summer peak demands of its retail customers. TEP hedges a portion of its total energy price exposure with forward priced contracts. TEP also purchases power in the daily and hourly markets: (i) to meet higher than anticipated demands; (ii) during periods of generation outages; or (iii) when doing so is more economical than generating its own power.
TEP is a member of a regional reserve-sharing organization and has reliability and power-sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as generation facility outages and system disturbances, which reduces the number of reserves TEP is required to carry as a participant in the regional reserve-sharing organization.
Peak Demand and Future Resources
Peak Demand
(in MW) 2023 2022 2021 2020 2019
Retail Customers 2,393 2,273 2,427 2,467 2,367
In 2023, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale peak demand, while maintaining a reserve margin in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional entity with delegated authority from NERC.
Peak demand occurs during the summer months due to the cooling requirements of retail customers in TEP’s service territory. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. The impacts of remote work as a result of COVID-19 have increased peak demand for residential customers since 2020. The decrease in retail peak demand in 2022 was primarily due to less extreme heat during peak load.
Forecasted retail peak demand for 2024 is 2,411 MW compared with actual peak demand of 2,393 MW in 2023. TEP’s 2024 estimated retail peak demand is based on weather patterns observed over a 10-year period and other factors, including estimates of customer usage. TEP believes that existing generation capacity and PPAs are sufficient to meet the expected demand and reserve margin requirements in 2024.
Future Resources
TEP's strategy on future resources is to continue its transition from carbon-intensive sources to a more sustainable energy portfolio, while maintaining reliability and ensuring rate affordability for its customers.
In November 2023, TEP filed with the ACC its 2023 IRP, which outlines its plan to accelerate its clean energy expansion to support anticipated growth and maintain affordable, reliable service as the Company works towards a new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps TEP on pace to reduce carbon emissions by 80% compared to 2005 by 2035, a goal that was set in TEP's 2020 IRP. The 2023 IRP proposes to achieve this goal by reducing the Company's dependency on coal-fired generation, while developing new renewable energy projects and energy storage projects, to meet electric demand. Investments in new natural gas-fired capacity will support the integration of these new renewable energy projects while maintaining system reliability and meeting future load growth.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information regarding TEP's 2023 IRP.
Fuel, Purchased Power, and Other Resources
A summary of fuel, purchased power, and other resource information is provided below:
Average Cost (cents per kWh) Percentage of Total kWh Resources
2023 2022 2021 2023 2022 2021
Coal 3.17 2.83 2.60 24 % 31 % 34 %
Natural Gas 3.27 5.36 3.36 48 % 42 % 46 %
Purchased Power, Non-Renewable 6.70 7.31 8.88 15 % 14 % 10 %
Total Non-Renewable 87 % 87 % 90 %
Purchased Power, Renewable 6.74 6.76 7.63 9 % 8 % 6 %
Utility-Owned, Renewable N/A N/A N/A 4 % 5 % 4 %
Total Renewable 13 % 13 % 10 %
Total Fuel, Purchased Power and Other Resources 100 % 100 % 100 %
Coal Supply
The coal used for generation is low-sulfur, bituminous or sub-bituminous coal sourced from mines in New Mexico. The table below provides information on the existing coal contracts that supply TEP's generation facilities. The average cost of coal per MMBtu, including transportation, was $2.92 in 2023, $2.65 in 2022, and $2.48 in 2021.
Station Coal Supplier 2023 Coal Consumption (tons in 000s) Contract Expiration Date Average Sulfur Content Coal Obtained From
Springerville Peabody CoalSales 1,941 2031 1.0% Lee Ranch Mine/El Segundo Mine
Four Corners NTEC 258 2031 0.7% Navajo Mine
The coal supplies for Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects to have access to coal supplies to fulfill the estimated requirements for each of the Springerville units over their respective remaining life.
Coal-Fired Generation Facilities Operated by Others
TEP also participates in a jointly-owned coal-fired generation facility at Four Corners. Four Corners, which is operated by APS, is a mine-mouth generation facility located adjacent to the coal reserves. TEP expects coal reserves available to this jointly-owned generation facility to be sufficient for the remaining life of the station.
Natural Gas Supply
The table below provides information on the natural gas transportation agreements that deliver natural gas to TEP's generation facilities. The average cost of natural gas per MMBtu, including transportation, was $3.72 in 2023, $8.35 in 2022, and $5.38 in 2021. The decrease in cost in 2023 compared to 2022 was primarily due to a decrease in natural gas prices resulting from high natural gas production and increased transportation capacity caused by natural gas pipelines restoration. The increase in cost in 2022 compared to 2021 was primarily due to an increase in natural gas prices resulting from increased demand and limited transportation capacity caused by constrained natural gas pipelines.
Station Natural Gas Transportation Counterparty Contract Expiration Date(s)
Gila Transwestern Pipeline Co./El Paso Natural Gas Company, LLC 2025-2040
Luna El Paso Natural Gas Company, LLC 2032
Sundt El Paso Natural Gas Company, LLC 2039-2048
DeMoss Petrie Southwest Gas Corporation Retail Tariff
North Loop Southwest Gas Corporation Retail Tariff
Transmission and Distribution
TEP's distribution and transmission facilities are located in Arizona and New Mexico. These facilities are located on property owned by: (i) TEP; (ii) public entities; (iii) private entities; and (iv) Tribal Nations. TEP's transmission and distribution systems included approximately 2,239 miles of transmission lines and 7,967 miles of distribution lines as of December 31, 2023.
TEP's transmission facilities transmit the output from TEP’s electric generation facilities to the Tucson area and power markets. The transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces, and parts of Mexico. TEP's transmission system, together with contractual rights on other systems, enables TEP to integrate and access generation resources to meet its energy load requirements.
ENVIRONMENTAL MATTERS
The EPA regulates, or has the authority to regulate, the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2), particulate matter, mercury, and other by-products produced by generation facilities. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its 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, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects recovery of the cost of environmental compliance through Retail Rates and cost recovery mechanisms.
Refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources of this Form 10-K for additional information related to environmental laws and regulations as well as environmental compliance capital expenditures.
HUMAN CAPITAL
As of December 31, 2023, TEP had 1,740 employees, of which approximately 763 were represented by the International Brotherhood of Electrical Workers Local No. 1116 (IBEW). The current collective bargaining agreement between the IBEW and TEP was ratified in June 2023 and is set to expire on June 30, 2028. TEP also engages with independent contractors in the ordinary course of its business, as necessary.
Culture
TEP strives to create a positive environment for its employees through various initiatives consistent with its values. The Company believes that the foundation for a diverse and inclusive work environment starts with the Executive Officers and Board of Directors' active involvement in tracking the Company's goals and objectives. TEP's business strategy includes a commitment to help employees thrive by adapting to change, investing in continuous learning, and promoting collaboration, inclusion, and diversity, while deepening the Company's safety culture.
TEP's compliance team and Board of Directors review the Company's Code of Ethics and Business Conduct (Code) annually and make updates based on direct feedback from employees. The Code serves as TEP's ethical compass and expressly states that the Company will not tolerate certain behaviors including: (i) retaliation; (ii) discrimination; (iii) harassment; or (iv) abuse of positions of trust for personal gain. The Code is intended to help TEP create a safe and respectful workplace where employees feel valued and secure.
Diversity, Equity, and Inclusion
Diversity, equity, and inclusion are an integral part of TEP’s vision and values. TEP values an inclusive culture and the unique contributions, perspectives, and experiences of its employees. TEP continues to identify and focus on behaviors that build strong and positive relationships at work to support an environment of thriving employees. TEP incorporates diversity, equity, and inclusion metrics into its annual goals and aligns these metrics with business objectives.
Business Resource Groups
The Company supports employee participation in Business Resource Groups (BRG), which are voluntary, employee-led groups that have established missions, goals, and practices that support career development and employee engagement and align with TEP's business priorities. Participants share ideas and issues to help promote an inclusive, equitable, and respectful workplace. Examples of BRGs that provide professional networking opportunities at TEP include:
•Veterans in Energy - dedicated to: (i) building relationships between its members; (ii) providing support and mentorship for military veterans and families; and (iii) promoting engagement and retention of military veteran employees.
•Women in Energy - dedicated to: (i) inspiring women in their professional growth; (ii) developing leadership qualities in women; and (iii) promoting engagement of women and diverse representation and thought.
•Native American, Tribal, and Indigenous Voices in Energy - dedicated to: (i) being a resource to Native Americans and creating a space of comfort and acceptance in the workplace; (ii) increasing visibility and representation of Native, Tribal, and Indigenous people in the energy field; and (iii) supporting and encouraging native employees in their professional growth.
Workforce Pipeline
TEP's workforce pipeline initiatives center on attracting, engaging, and developing a diverse workforce. Many of these efforts are specifically geared towards investing in: (i) students from historically underserved backgrounds from elementary schools through post-graduate studies; (ii) individuals with disabilities; and (iii) military veterans.
TEP is a Troops to Energy Jobs employer that works with the Center for Energy Workforce Development to match military skills with open positions in a variety of fields within the Company. TEP has sponsored numerous military internships for separating or retiring service members in partnership with Davis-Monthan Air Force Base, among other military bases. As of December 31, 2023, 11% of TEP's employees were military veterans.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Executive Officers, who are elected annually by TEP’s Board of Directors, acting at the direction of the Board of Directors of UNS Energy, as of January 1, 2024, are as follows:
Name Age Position(s) Held Executive Officer Since
Susan M. Gray (1)
51 President and Chief Executive Officer 2015
Frank P. Marino (1)
59 Senior Vice President and Chief Financial Officer 2013
Todd C. Hixon (1)
57 Senior Vice President, Chief Legal Officer, and Corporate Secretary 2011
Erik B. Bakken 51 Senior Vice President of Energy Resources and Chief Sustainability Officer 2018
Cynthia A. Garcia 56 Vice President of Energy Delivery and Safety and Chief Information Officer 2020
J. Caleb Adcock 40 Vice President, Finance 2023
Dallas J. Dukes 56 Vice President, Customer Experience, Programs and Pricing 2019
Orrin T. Nay 59 Vice President of Energy Resources 2022
Christopher W. Norman 48 Vice President, Public Policy and Corporate Strategy 2022
Michael E. Sheehan 56 Vice President of Resource Planning, Fuels and Wholesale Marketing 2020
Amy J. Welander 45 Vice President, General Counsel and Assistant Corporate Secretary 2023
Gail M. Zody-Serbia 46 Vice President of Human Resources 2022
Martha B. Pritz 62 Treasurer 2017
(1)Member of TEP's Board of Directors. The directors of TEP are elected annually by TEP's sole shareholder, UNS Energy, acting at the direction of the board of directors of UNS Energy.
SEC REPORTS AVAILABLE
TEP makes available its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practical after it electronically files or furnishes them to the SEC. The SEC maintains a website at https://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically. TEP's reports are also available free of charge through TEP’s website at https://www.tep.com/investor-information/.
TEP is providing the address of its website solely for the information of investors and does not intend for the address to be an active link. The information contained on TEP’s website is not a part of, or incorporated by reference into, any report or other filing by TEP filed with the SEC.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
The business and financial results of TEP are subject to a number of risks and uncertainties, including those set forth below. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational. Additional risks and uncertainties that are not currently known to TEP or that are not currently believed by TEP to be material may also negatively impact TEP’s business and financial results.
REVENUES
A significant decrease in the demand for electricity in TEP's service area would negatively impact retail sales and adversely affect results of operations, net income, and cash flows at TEP.
National and local economic conditions have a significant impact on customer growth and overall retail sales in TEP’s service area. TEP anticipates an annual customer growth rate of 1% for the next five years.
Research and development activities are ongoing for new technologies that produce power and/or reduce power consumption, such as renewable energy resources, including energy storage and customer-sited DG, energy-efficient products, and control systems. Continued development and use of these technologies and compliance with the ACC's EE Standards and RES continue to have a negative impact on TEP’s use per customer and overall retail sales. TEP's use per customer declined by an average of 1% per year from 2019 through 2023.
The revenues, results of operations, and cash flows of TEP are seasonal and are subject to weather conditions and customer usage patterns, which are beyond the Company’s control.
Retail Sales
TEP earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during the summer. Conversely, first quarter net income is limited by relatively mild winter weather in TEP's retail service territory. Unseasonably cool summers or warm winters may reduce customer usage, negatively affecting operating revenues, cash flows, and net income by reducing sales.
Production Tax Credits
Electricity generated from TEP's wind-powered facility depends heavily on wind conditions, turbine availability, and transmission capacity. If such conditions are unfavorable, the facility’s electricity generation and associated PTCs may be reduced, negatively affecting cash tax payments and net income.
TEP is dependent on a small number of customers for a significant portion of future revenues. A reduction in the electricity sales to these customers would negatively affect results of operations, net income, and cash flows at TEP.
TEP’s ten largest customers represented 10% of total revenues in 2023. TEP sells electricity to mines, military installations, and other large commercial and industrial customers. Retail sales volumes and revenues from these customers could decline as a result of, among other things: global, national, and local economic conditions; curtailments of customer operations due to unfavorable market conditions; military base reorganization or closure decisions by the federal government; the effects of energy efficiency; or the decision by customers to self-generate all or a portion of their energy needs. A reduction in retail kWh sales by any one of TEP’s ten largest customers would negatively affect the Company's results of operations, net income, and cash flows.
REGULATORY
TEP's business is significantly impacted by government legislation, regulation and oversight. TEP's inability to recover its costs, earn a reasonable return on its investments, or comply with current regulations would negatively affect its results of operations, net income, and cash flows.
TEP's financial condition is influenced by how regulatory authorities, including the ACC and the FERC, establish the rates TEP can charge customers and authorize rates of return, common equity levels, and the amount of costs that may be recovered from TEP customers. The Company's ability to timely obtain rate adjustments that provide TEP with the opportunity to earn authorized rates of return depends upon timely regulatory action under applicable statutes and regulations and cannot be guaranteed.
•ACC-The ACC is a constitutionally created body composed of five elected commissioners and has jurisdiction over rates for retail customers. Commissioners are elected state-wide for staggered four-year terms and are limited to
serving two consecutive terms. As a result, the composition of the ACC, and therefore its policies, are subject to change every two years.
•FERC-The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale.
Owners and operators of bulk power systems, including TEP, are subject to mandatory reliability standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new reliability standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory reliability standards could subject TEP to sanctions, including substantial monetary penalties.
Changes made to legislation, regulation, or regulatory structure could negatively affect TEP's results of operations, net income, and cash flows.
TEP incurs costs to comply with legislative and regulatory requirements and initiatives, including those relating to clean energy requirements, the deployment of distributed energy resources, and implementation of programs for demand response, customer energy efficiency, and electric vehicles. Initiatives or changes to existing requirements have occurred and could arise again in the future through legislative, regulatory, or other initiatives (including ballot initiatives) on either a federal, state, or local level.
TEP's ability to recover costs, including its investments, associated with legislative and regulatory initiatives will, in large part, depend on the final form of legislative or regulatory requirements. Further increases to rates could negatively affect the affordability of the rates charged to customers, which may negatively affect TEP’s results of operations, net income, and cash flows.
ENVIRONMENTAL
TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it to environmental-related litigation and liabilities.
Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions of conventional pollutants and GHGs, water quality and water use, wastewater discharges, solid waste, hazardous waste, and management of CCR. Policy initiatives, such as environmental justice that considers disproportionately adverse environmental impacts on vulnerable communities, may also impact operations.
We have incurred costs in connection with environmental compliance, and we anticipate that we will continue to do so in the future. These laws and regulations can contribute to higher capital expenditures and operating expenses, particularly resulting from enforcement efforts focused on existing generation facilities and compliance standards related to new and existing generation facilities. These laws and regulations generally require TEP to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations and policies. Failure to comply with applicable laws and regulations, or address certain policies, may result in litigation, as well as the imposition of fines, penalties, and requirements by regulatory authorities for costly equipment upgrades.
Existing environmental laws and regulations may be revised, and new environmental laws and regulations may be adopted or become applicable to the Company's facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a negative effect on TEP's results of operations, particularly if those costs are not timely and fully recoverable from TEP customers. TEP’s obligation to comply with these laws and regulations as a participant or owner in regulated facilities like Springerville and Four Corners, coupled with the financial impact of future climate change legislation, other environmental regulations and policies, and other business considerations, could jeopardize the economic viability of these generation facilities. Additionally, these regulations may jeopardize continued generation facility operations or the ability of individual participants to meet their obligations and willingness to continue their participation in these facilities potentially resulting in an increased operational cost for the remaining participants.
TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generation facilities in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generation facilities. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.
FINANCIAL
Early closures of TEP's coal-fired generation facilities could result in TEP recognizing regulatory impairments or increased cost of operations if recovery of TEP's remaining investments in such facilities and the costs associated with early closures are not permitted through rates charged to customers.
TEP's remaining coal-fired generation facilities may close before the end of their useful lives in response to economic conditions and/or changes in regulation, including any future changes to the ACC's energy rules and/or environmental regulations. If any coal-fired generation facilities from which TEP obtains power are closed prior to the end of their useful lives, TEP may need to seek regulatory recovery of the remaining net book value and could incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation, and cancellation of long-term coal contracts of such generation facilities. As of December 31, 2023, the net book value of TEP's in service coal-fired generation facilities was $1.0 billion.
Volatility, disruptions, or unfavorable changes in the financial markets, rising interest rates, or unanticipated financing needs, could increase TEP's financing costs, limit access to the credit or bank markets, affect the Company's ability to comply with financial covenants in debt agreements, and increase TEP's pension funding obligations. Such outcomes may negatively affect liquidity and TEP's ability to carry out the Company's financial strategy and fund the Company's operations.
We rely on access to bank and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flows from TEP's operations. Market disruptions such as those experienced in the financial crises of 2008, 2009, and 2020 in the United States and abroad may increase the Company's cost of borrowing or negatively affect TEP's ability to access sources of liquidity needed to finance the Company's operations and satisfy its obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions with which we do business, increases in interest rates, significant volatility in the bank and capital markets, and general economic downturns in TEP's utility service territory or in the broader economy. If TEP is unable to access credit at reasonable rates, or if the Company's borrowing costs dramatically increase, TEP's ability to finance its operations, meet debt obligations, and execute its financial strategy could be negatively affected. Increases in short-term interest rates would increase the cost of borrowings under TEP's credit facility.
In addition, unfavorable market conditions have and could continue to negatively affect the market value of assets held in its pension and other postretirement defined benefit plans and may increase the amount and accelerate the timing of required future funding contributions.
OPERATIONAL
The operation of generation facilities and transmission and distribution systems involves risks and uncertainties that could result in reduced generation capability or unplanned outages that could negatively affect TEP’s results of operations, net income, and cash flows.
The operation of generation facilities and transmission and distribution systems involves certain risks and uncertainties, including equipment breakdown or failures, fires and other hazards, lower than expected levels of efficiency or operational performance, and/or disruptions in operations due to union strikes or a labor shortage. Governmental actions and other circumstances that cause continued global supply chain challenges including lead time impacts, price volatility, and other market trends, have and could continue to increase the risk that TEP’s operations could be negatively impacted and/or TEP’s capital spending could increase. If TEP’s generation facilities or transmission and distribution systems operate below expectations, TEP’s operating results could be negatively affected and/or TEP's capital spending could be increased.
In addition, as coal-fired generation facilities are closed, the economic viability of coal mines and coal suppliers may be jeopardized. To date, several coal suppliers have declared bankruptcy and coal mines have been closed. As additional coal-fired generation facilities are closed, the availability of sufficient coal supplies could decrease and prices may increase, which could, in turn, negatively affect the viability of our remaining coal-fired generation facilities.
The operation of generation facilities and transmission systems on tribal lands may create operational and financial risks for TEP that, if realized, could negatively affect TEP’s results of operations, net income, and cash flows.
Certain jointly-owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements, or other rights-of-way that are effective for specified periods. TEP is unable to predict the final outcomes of pending and future approvals by the applicable sovereign governing bodies with respect to the cost of renewals and continued access to
these leases, land easements, and rights-of-way. If pending and future approvals are not obtained and if continued access to the facilities is not granted, it could negatively affect TEP's results of operations, net income, and cash flows.
TEP receives power from certain generation facilities that are jointly-owned with, or operated by, third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could negatively affect TEP’s results of operations, net income, and cash flows.
Certain generation facilities from which TEP receives power are jointly-owned with, or operated by, third parties. TEP does not have the sole discretion to affect the management or operations at such facilities. As a result of this reliance on other operators, TEP may not be able to ensure the proper management of the operations and maintenance of such generation facilities. Further, TEP may have limited ability to determine how best to manage the changing economic conditions or environmental requirements that may affect such facilities. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such facilities could negatively impact the business and operations of TEP.
The effects of climate change may create operational and financial risks for TEP that, if realized, could negatively affect TEP's results of operations, net income, and cash flows.
Climate change impacts regional and global weather conditions and results in extreme weather events, including high temperatures, severe thunderstorms, and drought. Changes in weather conditions and extreme weather have occurred in the Western United States and have affected TEP's transmission and distribution systems. In addition, extreme weather has increased the potential likelihood of wildfires. Both extreme weather events and wildfires could lead to service outages and business interruptions, either of which increase capital expenditures and operating expenses. There can be no assurance that physical utility assets will successfully withstand severe weather conditions or wildfires. A fire caused by our equipment may result in litigation where plaintiffs may assert claims alleging TEP is liable for resulting damages.
A prolonged drought in the southwestern United States has led to a regional decrease in surface water and groundwater accessibility. Drought conditions may result in: (i) additional regulation, impacting TEP's water use for generation; and (ii) regional power constraints, impacting power market prices. Regional water scarcity may also impact existing customers' operations and future economic development, affecting retail sales volumes and related revenue.
Other potential risks associated with changes in weather conditions, extreme weather events, and wildfires, including wildfires outside of TEP's service territory, include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. Any damage caused to our assets or disruption of service to our customers could lead to a negative impact on TEP's results of operations, net income, and cash flows.
TEP is subject to seasonal capacity shortfalls which could result in an inability for the Company to reliably serve load requirements and could negatively affect TEP’s results of operations, net income, and cash flows.
Increased capacity scarcity in the Western region may result in TEP's inability to meet customer demand. Conditions that could cause a capacity shortfall include but are not limited to: an extreme weather event, regulatory policy, fuel supply shortages related to constrained natural gas pipelines or coal delivery interruptions, coal mine or natural gas well field outages, increased customer demand, unplanned outages, including extensions of planned outages due to equipment failures or other complications, in-service delays of new generation and transmission resources, and/or the retirement of generation resources. These conditions may contribute to market price volatility and increased difficulty in procuring market energy. An inability to serve load requirements could negatively affect TEP’s results of operations, net income, and cash flows.
TEP is subject to physical attacks which could have a negative impact on the Company's business and results of operations.
TEP’s generation, transmission, and distribution assets are critical to the provision of electric service to our customers and stability of the bulk electric system. They also provide the framework for our service infrastructure. TEP is facing a heightened risk of physical attacks on the Company's electric assets. The Company's electric generation, transmission, and distribution assets are geographically dispersed and are often in rural or unpopulated areas which makes it especially difficult to adequately detect, defend from, and respond to such attacks. The Company relies on the continued operation of these assets, which are part of an interconnected regional electrical grid. Any significant interruption of these assets could prevent the Company from fulfilling its critical business functions including delivering energy to customers. Security threats continue to evolve and adapt. Such attempts could be motivated by a desire to disrupt utility operations or seek financial gain. TEP, the energy industry, and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to disrupt operations through physical security attacks and breaches. Such events or the threat of such events may increase costs associated with heightened
security requirements. Despite implementation of security measures, there can be no assurance that the Company will be able to prevent such disruptions.
If, despite TEP's security measures, a significant physical attack occurred, the Company could: (i) have operations disrupted, including a disruption to the stability of the bulk electric system, and/or property damaged; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations.
TEP is subject to cyber-attacks which could have a negative impact on the Company's business and results of operations.
Cybercrime, which includes the use of malware, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years due to heightened geopolitical instability, an increase in remote work, the increased use of smartphones, tablets, and other wireless devices, and the continued monetization of cybercrime. The Company is subject to inherent technological risk from hacking, software viruses, and other types of data security breaches. Furthermore, the nature and sophistication of cyber-attacks continues to evolve as cyber-attackers use Artificial Intelligence to develop malicious code and sophisticated phishing attempts and other attacks on operational control systems and data. The Company's utility business requires access to and retention of sensitive customer data, including personal and credit information, in the ordinary course of business. The Company relies on the continued operation of sophisticated digital information technology systems and network infrastructure to operate the utility as part of an interconnected regional electrical grid. TEP's operations technology systems face a heightened risk of cyber-attack due to the critical nature of such infrastructure.
TEP's information technology systems and network infrastructure have been subject to, and will likely continue to be subject to, cyber-attacks from foreign or domestic sources attempting to gain unauthorized access to information and/or information systems through computer viruses and phishing attempts either directly or indirectly through its material vendors or related third parties. Such attempts could be motivated by a desire to disrupt utility operations or seek financial gain.
If, despite TEP's security measures, a significant cybersecurity event or data breach occurred, the Company could: (i) have operations disrupted, have customer information stolen, and experience general business system and process interruption or compromise, including that which prevents TEP from servicing customers, collecting revenues or recording, processing and/or reporting financial information correctly; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations. See Part I, Item 1C Cybersecurity of this Form 10-K for a discussion of cybersecurity risk management, strategy, and governance, which should be read in conjunction with this Item 1A.
GENERAL RISK FACTORS
Changes in tax regulation may negatively affect the results of operations, net income, and cash flows of TEP.
The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. Legislation or regulation could be enacted by any of these governmental authorities, which could affect the Company’s tax positions, results of operations, net income, and cash flows. The IRA was enacted on August 16, 2022. TEP is currently assessing the overall impacts of this legislation and interpretive guidance from tax authorities relating thereto.
The failure to attract, retain, and manage an appropriately qualified workforce could negatively impact TEP’s business and results of operations.
TEP’s business is dependent on its ability to attract, retain, and manage qualified personnel, including key executive officers and skilled professional and technical employees and contractors. Certain events and conditions, such as an aging workforce without available replacements, a shift in employee expectations with respect to compensation and flexible work arrangements, the unavailability of contract resources, and the ongoing need to negotiate collective bargaining agreements with union employees, may lead to significant operating challenges, including lack of resources, loss of knowledge base, time required for skill development, and labor disruptions. If TEP is unable to successfully attract, retain, and manage an appropriately qualified workforce, its business and results of operations could be negatively affected.
Events beyond our control, such as public health crises, geopolitical tensions, natural disasters, or other catastrophic events, could adversely affect our business, results of operations and financial condition.
TEP could be negatively impacted by various events beyond our control, including, without limitation, public health crises, geopolitical tensions and other political instability, natural disasters, or other catastrophic events, whether occurring locally, nationally, or globally. Any of the forgoing events and any resulting impact, such as economic and/or trade disruptions,
including the disruption of global supply chains and volatility and disruption of financial markets, labor shortages, or government-mandated actions in response to any such event could materially affect TEP’s business, results of operations, access to sources of liquidity, and financial condition, either directly or through the impact on third parties upon whom we rely.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
TEP's corporate headquarters and operational support facilities for Tucson operations are owned by TEP and located in Tucson, Arizona.
TEP has land easements for transmission facilities related to San Juan, Four Corners, and Navajo located on tribal lands of the Zuni, Navajo, and Tohono O’odham Nations. Four Corners and Navajo are located on properties held under land easements from the United States and under leases from the Navajo Nation. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna is located.
TEP’s rights under various land easements and leases may be subject to defects such as:
•possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs and the Tribal Nations;
•possible inability of TEP to legally enforce its rights against adverse claims and the Tribal Nations without Congressional consent; or
•failure or inability of the Tribal Nations to protect TEP’s interests in the land easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claims.
These possible defects have not interfered, and are not expected to materially interfere with TEP’s interest in and operation of its facilities.
TEP's rights under land easements expire at various times and renewal action by the applicable tribal or federal agencies is required. The ultimate cost of renewal for certain of the rights-of-way for the Company's transmission lines is uncertain. The principal owned generation, distribution, and transmission facilities of TEP are described in Part I, Item 1. Business, Overview of Business and such descriptions are incorporated herein by reference.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company believes such normal and routine litigation will not have a material impact on its operations or financial results.
See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
TEP’s common stock is wholly-owned by UNS Energy and is not listed for trading on any stock exchange.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the financial condition, and the outlook for TEP. It includes the following:
•outlook and strategies;
•factors affecting results of operations;
•results of operations;
•liquidity and capital resources, including capital expenditures, income tax position, and environmental matters;
•critical accounting estimates; and
•new accounting standards issued and adopted or not yet adopted.
Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP.
This section of this Form 10-K primarily discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 activity and year-to-year comparisons between 2022 and 2021 that are not included in this Form 10-K can be found in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for our fiscal year ended December 31, 2022.
Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes in Part II, Item 8 of this Form 10-K. For information on factors that may cause our actual future results to differ from those we currently anticipate, see Forward-Looking Information and Part I, Item 1A. Risk Factors of this Form 10-K.
References in this 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 from carbon-intensive sources to a more sustainable energy portfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. In November 2023, we announced our new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps us on pace to reduce carbon emissions by 80% compared to 2005 by 2035. The establishment of this additional target reinforces our commitment to decarbonize over the long-term, while preserving customer reliability and affordability. These goals may be impacted by various federal and state energy policies, including policies currently under consideration.
•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 - 2023 Compared with 2022
We reported net income of $259 million in 2023 compared with $217 million in 2022. The increase of $42 million, or 19%, was primarily due to:
•$43 million in higher retail revenue primarily due to: (i) an increase in rates as approved in the 2023 Rate Order; (ii) higher usage as a result of favorable weather; and (iii) higher LFCR revenues;
•$13 million in lower depreciation expense primarily due to the retirement of San Juan Unit 1 in June 2022;
•$10 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of favorable market conditions;
•$8 million in higher interest income due to an increase in interest earned on the PPFAC regulatory asset; and
•$8 million in higher AFUDC due to an increase in eligible construction expenditures.
The increase was partially offset by:
•$10 million in higher net periodic non-service cost as a result of an increase in interest cost and a decrease in expected return on plan assets;
•$9 million in higher income tax expense primarily due to an increase in taxable earnings and lower tax credits primarily related to Oso Grande PTCs;
•$9 million in higher base operations and maintenance expenses primarily due to an increase in outside service expenses and higher maintenance costs at our generation facilities; partially offset by a decrease in operating expenses due to the retirement of San Juan Unit 1 in June 2022; and
•$9 million in higher interest expense primarily due to the issuance of debt in February 2023; partially offset by the retirement of debt in March 2023.
FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to regulatory matters, generation resource strategy, and weather patterns.
Regulatory Matters
We are subject to comprehensive regulation. The discussion below contains material developments in those matters.
2023 Rate Order
In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:
•a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;
•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% and an average cost of debt of 3.82%;
•a capital structure for rate making purposes of approximately 54% common equity and 46% long-term debt;
•approval to recover costs of changes in generation resources, including the addition of Oso Grande in rates; and
•denial of a request for a System Reliability Benefit adjustor that was designed to provide more timely recovery of our energy resource investments.
In January 2023, the ACC ordered that funding for the just and equitable transition away from fossil fuel-based economies for communities impacted by early coal-fired plant closures be considered as part of the 2023 Rate Order. In the 2023 Rate Order, the ACC determined that there was insufficient evidence to support customer funding for the just and equitable transition as part of the proceeding.
Generation Resource Strategy
Our long-term strategy is to continue our shift from carbon-intensive sources to a more sustainable energy portfolio by expanding renewable energy and natural gas resources while reducing reliance on coal-fired generation resources. In November 2023, we filed our 2023 IRP with the ACC, which outlines our plan to accelerate our clean energy expansion 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.
In 2022, we issued an All-Source Request for Proposal (ASRFP), which requested all resource types, including, among others, new wind and solar generation, energy storage systems, and energy efficiency resources. We received bids for many resource types and, as a result of this process, we entered into an EPC agreement in September 2023 to develop Roadrunner Reserve I, which is expected to be placed in service in the second half of 2025. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to our commitment with respect to Roadrunner Reserve I. In December 2023, we issued another ASRFP targeting in-service dates of 2026 through 2027, based on the resource needs outlined in our 2023 IRP, including natural gas-fired generation.
Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations and policies, and, for jointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we plan to exit all ownership interests in coal-fired generation facilities over the next decade. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings.
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 $15 million and $19 million in PTCs related to Oso Grande in 2023 and 2022, respectively. The PTC rate published by the IRS for electricity produced by a qualified facility using wind placed in service prior to 2022 was $0.028 for 2023 and $0.026 for 2022.
Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, or if other production constraints exist, the project's electricity generation and associated PTCs may be substantially different than forecasted. As of September 1, 2023, Oso Grande is included in rates as part of the 2023 Rate Order.
Weather Patterns
Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year due to mild winter weather in our retail service territory. Seasonal fluctuations affect the comparability of our results of operations.
Interest Rates
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this Form 10-K 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, DSM, and TEAM are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K 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, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Consolidated Statements of Income.
The following discussion provides the significant items that affected our results of operations for the year ended 2023 compared to 2022 presented on a pre-tax basis.
Operating Revenues
The following table provides a disaggregation of Operating Revenues:
Years Ended December 31, Increase (Decrease) Year Ended
December 31, Increase (Decrease)
(in millions) 2023 2022 Percent 2021 Percent
Operating Revenues
Retail (1)
$ 1,283 $ 1,140 12.5 % $ 1,088 4.8 %
Wholesale, Long-Term 76 99 (23.2) % 54 83.3 %
Wholesale, Short-Term (2)
253 330 (23.3) % 238 38.7 %
Transmission 56 62 (9.7) % 50 24.0 %
Springerville Units 3 and 4 Participant Billings 111 90 23.3 % 95 (5.3) %
Other 96 87 10.3 % 68 27.9 %
Total Operating Revenues $ 1,875 $ 1,808 3.7 % $ 1,593 13.5 %
(1)In December 2023, the ACC approved a revision to the TCA plan of administration to credit retail customers with transmission revenue associated with line losses in connection with wholesale customers that take transmission service under our OATT. The amendment reduces our retail revenues beginning in December 2023. Transmission revenue associated with line losses was $14 million in 2023 and averaged $15 million over the past three years. We have reduced the retail revenue requirement to be collected through the TCA by $10 million in 2024 for revenue associated with line losses. If revenue associated with line losses for the period is more or less than the forecasted revenue, the over or under collection will be subtracted from or added to the TCA revenue requirement for the subsequent period.
(2)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 $1,875 million in 2023 compared with $1,808 million in 2022. The increase of $67 million, or 4%, was primarily due to:
•$143 million in higher retail revenue primarily due to: (i) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate; (ii) an increase in rates as approved in the 2023 Rate Order; and (iii) higher usage as a result of favorable weather;
•$21 million in higher participant billings primarily related to Springerville Unit 3; and
•$9 million in higher other revenue primarily due to an increase in LFCR revenues.
The increase was partially offset by:
•$77 million in lower short-term wholesale revenue primarily due to a decrease in price; and
•$23 million in lower long-term wholesale revenue primarily due to a decrease in volume.
The following table provides key statistics impacting Operating Revenues:
Years Ended December 31, Increase (Decrease) Year Ended
December 31, Increase (Decrease)
(kWh in millions) 2023 2022 Percent 2021 Percent
Electric Sales (kWh) (1)
Retail Sales
8,954 8,810 1.6 % 8,718 1.1 %
Wholesale, Long-Term 1,314 1,659 (20.8) % 837 98.2 %
Wholesale, Short-Term 4,486 4,203 6.7 % 5,643 (25.5) %
Total Electric Sales 14,754 14,672 0.6 % 15,198 (3.5) %
Average Revenue per kWh (2)
Retail 14.33 12.94 10.7 % 12.48 3.7 %
Wholesale, Long Term 5.79 5.99 (3.3) % 6.46 (7.3) %
Wholesale, Short-Term 5.23 7.62 (31.4) % 4.15 83.6 %
Total Retail Customers (3)
446,762 442,751 0.9 % 438,357 1.0 %
(1)These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.
(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
(3)This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining), industrial (non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.
Operating Expenses
Fuel and Purchased Power Expense
We reported Fuel and Purchased Power expense of $756 million in 2023 compared with $771 million in 2022. The decrease of $15 million, or 2%, was primarily due to $132 million in lower Fuel expense due to a decrease in natural gas prices; partially offset by higher realized losses on natural gas swaps and an increase in Gas-Fired Generation volumes.
The decrease was partially offset by:
•$108 million increase in PPFAC Recovery Treatment and a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; and
•$12 million in higher Purchased Power Expense primarily due to an increase in volumes.
The following table provides key statistics impacting Fuel and Purchased Power:
Years Ended December 31, Increase (Decrease) Year Ended December 31, Increase (Decrease)
(kWh in millions) 2023 2022 Percent 2021 Percent
Sources of Energy
Coal-Fired Generation 3,688 4,626 (20.3) % 5,309 (12.9) %
Gas-Fired Generation 7,336 6,459 13.6 % 7,285 (11.3) %
Utility-Owned Renewable Generation 654 816 (19.9) % 648 25.9 %
Total Generation 11,678 11,901 (1.9) % 13,242 (10.1) %
Purchased Power, Non-Renewable 2,267 2,152 5.3 % 1,662 29.5 %
Purchased Power, Renewable 1,363 1,299 4.9 % 938 38.5 %
Total Generation and Purchased Power (1)
15,308 15,352 (0.3) % 15,842 (3.1) %
(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal 3.17 2.83 12.0 % 2.60 8.8 %
Natural Gas (3)(4)
3.27 5.36 (39.0) % 3.36 59.5 %
Average Cost of Purchased Power (5)
Purchased Power, Non-Renewable 6.70 7.31 (8.3) % 8.88 (17.7) %
Purchased Power, Renewable 6.74 6.76 (0.3) % 7.63 (11.4) %
(1)This number represents the kWh generated from our generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.
(2)This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation facilities.
(3)Includes realized gains and losses from hedging activity.
(4)In 2022, natural gas prices increased due to extreme weather and limited transportation capacity caused by constrained natural gas pipelines.
(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 $445 million in 2023 compared with $405 million in 2022. The increase of $40 million, or 10%, was primarily due to:
•$18 million in higher reimbursable maintenance expense related to Springerville Unit 3 primarily due to planned outages; partially offset by lower reimbursable maintenance related to Springerville Unit 4;
•$12 million in higher RES and DSM expenses; and
•$5 million in higher operations and maintenance expenses at our generation facilities and outside service expenses; partially offset by a decrease in operating expenses due to the retirement of San Juan Unit 1 in June 2022.
Depreciation and Amortization Expense
We reported Depreciation and Amortization expense of $236 million in 2023 compared with $251 million in 2022. The decrease of $15 million, or 6%, was primarily due to a $28 million decrease due to the retirement of San Juan Unit 1.
The decrease was partially offset by:
•$9 million increase due to an increase in rates approved by the ACC in the 2023 Rate Order; and
•$7 million increase due to an increase in asset base.
Other Income (Expense)
We reported Other Expense of $63 million in 2023 compared with $67 million in 2022. The decrease of $4 million, or 6%, was primarily due to:
•$10 million increase due to changes in the value of investments used to support certain post-employment benefits as a result of favorable market conditions;
•$9 million in higher interest income primarily due to an increase in interest earned on the PPFAC regulatory asset; and
•$7 million in higher AFUDC primarily due to an increase in eligible construction expenditures.
The decrease was partially offset by:
•$12 million in higher net periodic non-service cost primarily due to an increase in interest cost and a decrease in expected return on plan assets; and
•$10 million in higher interest expense primarily due to the issuance of debt in February 2023.
Income Tax Expense
We reported Income Tax Expense of $49 million in 2023 compared with $32 million in 2022. The increase of $17 million, or 53%, was primarily due to:
•$15 million in higher tax expense due to an increase in taxable earnings; and
•$5 million in lower tax credits primarily related to Oso Grande PTCs.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Any extended period of economic disruption could affect our business, 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) December 31, 2023
Cash and Cash Equivalents $ 9
Amount Available under Revolving Credit Agreement (1)
Total Liquidity $ 259
(1)The 2021 Credit Agreement provides for revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026. See Access to Credit below.
Future Liquidity Requirements
We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include but are not limited to: (i) dividend payments; (ii) debt maturities; (iii) employee benefit obligations; and (iv) known commitments and other contractual obligations including forecasted capital expenditures.
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk for additional information regarding our market risks and Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding our financing arrangements.
Summary of Cash Flows
The table below presents net cash provided by (used for) operating, investing, and financing activities:
Years Ended Increase
(Decrease) Year Ended Increase
(Decrease)
(in millions) 2023 2022 Percent 2021 Percent
Operating Activities $ 560 $ 509 10.0 % $ 428 18.9 %
Investing Activities (633) (510) 24.1 % (549) (7.1) %
Financing Activities 65 19 242.1 % 72 (73.6) %
Net Increase (Decrease) (8) 18 * (49) *
Beginning of Period 51 33 54.5 % 82 (59.8) %
End of Period (1)
$ 43 $ 51 (15.7) % $ 33 54.5 %
* Not meaningful
(1)Calculated on rounded data and may not correspond exactly to amounts on the Consolidated Statements of Cash Flows.
Operating Activities
Net cash flows provided by operating activities increased by $51 million in 2023 compared with 2022 primarily due to: (i) lower accounts receivable balances due to a decrease in power market prices; and (ii) higher retail revenue primarily due to higher PPFAC cost recoveries as a result of a higher PPFAC rate. The increase is partially offset by a decrease in accounts payable due to a decrease in energy market prices.
Investing Activities
Net cash flows used for investing activities increased by $123 million in 2023 compared with 2022 primarily due to an increase in cash paid for capital expenditures in 2023.
Financing Activities
Net cash flows provided by financing activities increased by $46 million in 2023 compared with 2022 primarily due to a decrease in dividends declared and paid to UNS Energy.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of December 31, 2023, we had no short-term investments.
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. In June 2023, the 2021 Credit Agreement was amended to provide for the transition to SOFR-based borrowings. As of December 31, 2023, there was $250 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings. As of February 8, 2024, there was $235 million available under the 2021 Credit Agreement.
See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this 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 TEP financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate. 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 February 2023, we issued and sold $375 million aggregate principal amount of 5.50% senior unsecured notes due April 2053. We used the net proceeds to redeem and repay debt and for general corporate purposes.
•In March 2023, we repaid at maturity $150 million aggregate principal amount of 3.85% senior unsecured notes.
•In March 2023, we redeemed at par prior to maturity $91 million aggregate principal amount of tax-exempt bonds bearing interest at a rate of 4.00% per annum.
We anticipate issuing long-term debt in 2024.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2023, 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 December 31, 2023, we were in compliance with these covenants.
We do not have any provisions in any of our debt agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
Contributions from Parent
We received no equity contributions from UNS Energy in 2023 and 2022.
Dividends Declared and Paid to Parent
We declared and paid $64 million in dividends to UNS Energy in 2023 and $100 million in 2022.
Master Trading Agreements
We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of December 31, 2023, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.
Capital Expenditures
Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. We prioritize capital projects to mitigate supply chain risk, particularly in view of heightened geopolitical instability and global supply chain challenges. In 2023, total capital expenditures of $578 million 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. In 2022, total capital expenditures of $458 million included: (i) investments in distribution and transmission assets, including initial payments for the construction of the Vail to Tortolita 230kV transmission line and a payment for a transmission right of way; and (ii) final payments for the Raptor Ridge solar project.
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)
$ 188 $ 185 $ 283 $ 550 $ 306
Other Generation Facilities (2)
33 40 22 60 34
Total Generation Facilities 221 225 305 610 340
Transmission and Distribution (3)
409 258 238 237 267
General and Other (4)
63 64 77 66 66
Total Capital Expenditures $ 693 $ 547 $ 620 $ 913 $ 673
(1)Includes investments in renewable energy and Roadrunner Reserve I in alignment with our long-term strategy of transitioning to a more sustainable energy portfolio. In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I at a cost of $294 million. See Note 8 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-K for additional information on the EPC agreement.
(2)Includes investments in existing facilities, including upgrades to ensure reliability.
(3)Investments in transmission capacity and distribution system reliability.
(4)Includes costs for information technology, fleet, facilities, and communication equipment.
These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, including inflationary pressures, construction schedules, labor shortages and/or labor strikes, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, new or changing commitments, and other factors. We expect to pay for forecasted capital expenditures with
internally generated funds and external financings, which may include issuances of long-term debt, other borrowings, or equity contributions.
Income Tax Position
Among other provisions included in the IRA, the legislation enacted a new Corporate Alternative Minimum Tax (CAMT) of 15% that is effective for tax years beginning after December 31, 2022. We are subject to the CAMT due to our membership in the Fortis consolidated tax group. The CAMT had no material impact on our financial results as of December 31, 2023 and is not currently expected to have a material impact on our financial results over the next five-year period.
Under the terms of the tax sharing agreement with UNS Energy, we made $6 million in net tax sharing payments in 2023 and received net refunds of $5 million in 2022. Future cash flows 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 SO2, NOx, 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.
We capitalized $5 million in 2023 and $2 million in 2022 in costs incurred to comply with environmental rules and regulations. In addition, we recorded operations and maintenance expenses related to environmental compliance of $6 million in each of 2023 and 2022. We expect environmental compliance related capital expenditures of $1 million in each of 2024 and 2025 and less than $1 million in each of 2026, 2027 and 2028. We will request recovery from our customers 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 ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluation.
We conducted the potential emissions controls evaluation, commonly referred to as the four-factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP. In August 2022, the ADEQ submitted the revised SIP to the EPA, and the EPA issued a letter to the ADEQ finding Arizona's SIP revision complies with the completeness criteria outlined in the rule. By statute, the EPA has one year from the completeness determination to take action on Arizona's SIP revision. Based on current Regional Haze requirement timeframes, we anticipate that compliance strategies, if any, will likely be required to be implemented one year following EPA approval of ADEQ's revised SIP. We cannot predict the outcome of this matter but will continue to work with the ADEQ to determine compliance strategies as needed.
Greenhouse Gas Regulation
In August 2015, the EPA issued the Clean Power Plan (CPP) limiting CO2 emissions from existing and new fossil fuel-based generation facilities. The CPP established state-level CO2 emission rates and mass-based goals that applied to fossil fuel-based generation.
In June 2019, the EPA repealed the CPP and issued the Affordable Clean Energy (ACE) rule, establishing new emission guidelines for existing coal-fired generation facilities based on the Best System of Emission Reduction (BSER) for GHG emissions. The BSER for GHG emissions from existing coal-fired generation facilities is defined as Heat-Rate Improvements that can be applied at the source. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the remaining useful life of an individual unit.
In January 2021, the U.S. Court of Appeals for the D.C. Circuit: (i) vacated the EPA's repeal of the CPP and remanded it back to the EPA for further consideration (the vacatur was later stayed by the court); and (ii) vacated and remanded the ACE rule. Certain petitioners, defending the repeal of the CPP, filed petitions for an order requesting that the U.S. Supreme Court review the decision of the lower court. The U.S. Supreme Court granted the petitions, consolidated the cases, and in June 2022, reversed the D.C. Circuit and remanded the cases back for further proceedings.
In May 2023, the EPA published a proposed GHG rule addressing GHG emissions from fossil fuel-fired electric generating units. The proposed rule also provides for the repeal of the ACE rule. Public comment closed on August 8, 2023. We cannot predict the outcome of this rulemaking at this time.
Coal Combustion Residuals Regulation
In April 2015, the EPA published final rules effective October 2015, which established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The CCR rules provide for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at the Springerville Generating Station. APS, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility.
In May 2023, the EPA published a proposal that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. EPA proposes to establish two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCR management units which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. As proposed, a CCR management unit would include not only historically closed landfills and surface impoundments, but also prior applications of CCR on land such as for structural fill. The EPA expects to finalize this proposal before summer 2024.
We are analyzing the EPA’s pending proposals and cannot predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending. At this time, we do not anticipate our share of the cost to complete any corrective actions to close the CCR disposal units, or to gather and perform remedial evaluations on groundwater at Four Corners Units 4 and 5, will have a significant impact on our operations, financial position, or cash flows.
Good Neighbor Federal Implementation Plan
In September 2018, the ADEQ submitted to the EPA the Arizona State Implementation Plan Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone National Ambient Air Quality Standard (NAAQS). In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.
In March 2023, the EPA released its final Federal Implementation Plan (FIP) to address the interstate transport of ozone (Good Neighbor FIP). The Good Neighbor FIP was published in the Federal Register in June 2023, with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.
In January 2024, the EPA released a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona’s inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOx emission reduction requirements. The EPA must take final action on Arizona’s Ozone Transport SIP Revision by August 30, 2024, per consent decree entered in the U.S. District Court for the Northern District of California. We cannot predict the outcome of this rulemaking at this time.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with GAAP requires management to apply accounting policies and to make estimates 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 the areas described below require significant judgment in the
application of accounting policy or in making estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on TEP’s other significant accounting policies can be found in Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
Accounting for Regulated Operations
We account for our regulated electric operations in accordance with accounting standards that allow the actions of our regulators, the ACC and the FERC, to be reflected in our financial statements. Regulator actions may cause us to capitalize certain costs that would be recorded as an expense, or in AOCI, in the current period by unregulated companies. We evaluate regulatory assets and liabilities each period and believe future recovery or settlement is probable. Our assessment includes consideration of recent rate orders, historical regulatory treatment of similar costs, and changes in the regulatory and political environment. If management's assessment is ultimately different than actual regulatory outcomes, the impact on our results of operations, financial position, and future cash flows could be material.
As of December 31, 2023, regulatory liabilities net of regulatory assets in the balance sheet totaled $158 million. There are no current or expected changes in the regulatory environment that impact our ability to apply accounting guidance for regulated operations. If we conclude in a future period that our operations no longer meet the criteria in this guidance, we will record our pension and other postretirement benefit plan regulatory assets or liabilities in AOCL and recognize other regulatory assets and liabilities in the income statement. The impact of this change would be material to our financial statements. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding regulatory matters.
Plant Asset Depreciable Lives
We have significant investments in electric generation, transmission, and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and estimated net removal costs. The ACC approves depreciation rates for all generation, distribution, and general plant assets. Depreciation rates for these assets cannot be changed without the ACC's approval. Our transmission assets are subject to the jurisdiction of the FERC. The useful lives of plant assets are further detailed in Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded in the income statement. See Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding depreciation rates.
Accounting for Asset Retirement Obligations
GAAP requires us to record the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. We incur legal obligations as a result of environmental regulations imposed by state and federal regulators, contractual agreements, and other factors. To estimate the liability, management must use judgment and assumptions in determining or estimating: (i) whether a legal obligation exists to remove assets; (ii) the probability of a future event for a conditional obligation; (iii) the fair value of the cost of removal; (iv) when final removal will occur; and (v) the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to our judgment and assumptions will change amounts recorded in the future as expense for AROs. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and amortized over the useful life of the related asset. Accretion of the liability and amortization of the asset are recorded as a regulated asset to be recovered through depreciation rates.
We identified legal obligations to retire generation facilities specified in land leases for our jointly-owned Four Corners, Navajo and San Juan facilities. Four Corners and Navajo reside on land leased from the Navajo Nation. The provisions of the Four Corners' lease require the lessees to remove the facilities at Four Corners upon request of the Navajo Nation at expiration of the lease. We are currently incurring costs to remove facilities at Navajo at the request of the Navajo Nation. We also have certain environmental obligations at Gila River, Luna, Sundt and Springerville. We estimate that our share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt, Gila River, and Springerville environmental and contractual obligations will be approximately $179 million at the retirement dates. Additionally, we entered into land lease agreements or land easement agreements with certain landowners for the installation of PV and wind assets. The provisions of the PV and wind land leases or land easements require us to remove the PV or wind facilities upon expiration of the agreements. In addition, we are required to properly dispose of or recycle certain PV assets under the Resource Conservation and Recovery Act. We estimate our ARO related to the PV and wind assets to be approximately $50 million at the retirement dates. We have identified no other legal obligations to retire generation assets.
We have various transmission and distribution lines that operate under land easements and rights-of-way that contain end dates and may contain site restoration clauses. We operate transmission and distribution lines as if they will be operated in perpetuity and will continue to be used or sold without land remediation. As such, there are no AROs for these assets.
The total net present value of our ARO liability recorded in Other on the Consolidated Balance Sheets was $114 million as of December 31, 2023. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.
Additionally, ACC approved depreciation rates include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances are recorded as a regulatory liability and represent non-legal estimated cost of removal accruals, net of actual removal costs incurred and salvage proceeds realized. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding future net cost of removal.
Pension and Other Postretirement Benefit Plan Assumptions
We record the underfunded amount for our pension and other postretirement obligations as a current liability, noncurrent liability, or combination of both, and record the overfunded amount as a noncurrent asset. For plans other than the SERP, amounts not yet recognized in the income statement are recorded as a regulatory asset or liability to reflect expected recovery or refund of pension and other postretirement obligations or benefits through rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability and asset balances may vary significantly in future years. Key assumptions used include:
•discount rates used to determine obligations;
•expected returns on plan assets;
•compensation increases;
•mortality assumptions; and
•healthcare cost trend rates.
Discount Rates
As of December 31, 2023, we discounted our future pension plan obligations at a rate of 5.4% and our other postretirement benefit plan obligations at a rate of 5.2%. The discount rate for future pension plan and other postretirement benefit plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments.
Expected Returns on Plan Assets
To establish the expected return on assets assumption, we review the asset allocation and develop return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward-looking views of the financial markets. As of December 31, 2023, we assumed that our pension plans’ assets would generate a long-term rate of return of 7.5%.
Compensation Increases
As of December 31, 2023, we used a rate of compensation increase of 3.2% to measure pension obligations.
Mortality
The PRI-2012 mortality table projected with a version of improvement scale MP-2021 modified to remove improvements for 2020-2023 due to COVID-19 and with a 15-year convergence and a 0.75% long-term rate was utilized to measure pension obligations as of December 31, 2023. The PRI-2012 mortality table projected with a modified version of improvement scale MP-2020 with 15-year convergence and a 0.75% long-term rate was utilized to measure pension obligations as of December 31, 2022.
Healthcare Cost Trend Rates
We used a current year healthcare cost trend rate range between 5.8% and 7.3% in valuing our other postretirement benefit obligation as of December 31, 2023. This rate reflects both market conditions and historical experience.
Sensitivity Analysis
The table below shows the effect on our expense and obligation of a 100-basis point change to its assumptions as of December 31, 2023:
Effect on Expense Effect on Obligation
(in millions) Increase Decrease Increase Decrease
Change to Pension
Discount Rate $ (5) $ 6 $ (56) $ 70
Long-Term Rate of Return on Plan Assets (4) 4 N/A N/A
Change to Other Postretirement Benefits
Discount Rate (1) 1 (8) 10
Long-Term Rate of Return on Plan Assets - - N/A N/A
Healthcare Cost Trend Rate 1 (1) 8 (7)
In 2024, we will incur net periodic pension benefit costs of $12 million and net periodic other postretirement benefit costs of $6 million. We expect to record: (i) $15 million to operations and maintenance expense; (ii) $4 million to capital; and (iii) $1 million to other income. In 2024, we expect to make pension plan contributions of $11 million and other retiree benefit payments of $6 million.
See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension plans and other postretirement benefit plan expenses and obligations.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
We enter into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, one year, or three years, within established limits to meet forecasted load requirements or to take advantage of favorable market opportunities. In general, we enter into forward purchase contracts when market conditions provide the opportunity to purchase energy for our load at prices that are below the marginal cost of our supply resources or to supplement our own resources (e.g., during plant outages and summer peaking periods). We enter into forward sales contracts when we forecast that we will have excess supply, and the market price of energy exceeds our marginal cost. We enter into forward natural gas commodity price swap agreements to lock in fixed prices on a portion of forecasted natural gas purchases and fixed price purchased power agreements to hedge the price risk associated with forward PPAs.
For all commodity derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities in the balance sheet and measure those instruments at fair value. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or liability in the balance sheet based on our ability to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC mechanism.
The market prices used to determine fair values for our derivative instruments as of December 31, 2023, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.
NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED OR NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP is exposed to certain market risks that can affect asset and liability fair value, results of operations, and cash flows. TEP's significant market risks are primarily associated with commodity prices, interest rates, and extension of credit to counterparties. TEP may enter into interest rate swaps and financing transactions to manage changes in interest rates. TEP has a Risk Management Committee (RMC) responsible for the oversight of commodity price risk and credit risk related to wholesale energy marketing and power procurement activities. To limit TEP’s exposure to commodity price risk, the RMC sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP’s exposure to credit risk, the RMC reviews counterparty credit exposure as well as credit policies and limits on a regular basis.
Commodity Price Risk
TEP is exposed to market fluctuations in electricity, natural gas, and coal prices as a result of its obligation to serve retail customer load in its regulated service territory and long-term wholesale contracts. Exposure to commodity prices consists primarily of variations in the price of fuel required to generate electricity that is purchased and sold in retail and wholesale markets. Commodity prices may be subject to significant price changes as supply and demand are impacted by, among other unpredictable factors, weather, market liquidity, generation facility availability, customer usage, energy storage, and transmission and transportation constraints. Under the guidance of its RMC, TEP mitigates a portion of commodity price risk using forwards, financial swaps, and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. TEP also mitigates exposure to commodity price risk with its ability to recover these costs in regulated rates through its PPFAC mechanism, which is subject to an annual review by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.
Certain commodity contracts qualify as derivatives and are recorded at fair value. The changes in fair value of such contracts have a high correlation to price changes in the hedged commodities. The following table shows the changes in fair value of TEP's derivative positions:
(in millions) 2023 2022 2021
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (81) $ 72 $ 62
TEP's derivative contracts mature on various dates through 2029. The table below displays the valuation methodologies and maturities of derivative contracts by source of fair value:
Unrealized Gain (Loss) of TEP’s Hedging Activities
Maturity 0 - 6 months Maturity 6 - 12 months Maturity over 1 yr. Total Unrealized Gain (Loss)
(in millions) December 31, 2023
Prices Actively Quoted $ (11) $ (11) $ 27 $ 5
Sensitivity Analysis of Derivatives
TEP uses sensitivity analysis to measure the potential impact of favorable and unfavorable changes in market prices on the fair value of its derivative contracts. TEP primarily records unrealized gains and losses as either a regulatory asset or liability, respectively. As contracts settle, unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. For derivatives related to the purchase and sale of power, a 10% change in the market price of purchased power would affect unrealized positions reported as a regulatory asset or liability by approximately $2 million. For derivatives related to natural gas price hedges, a 10% change in the market price of energy would affect unrealized positions reported as a regulatory asset or liability by approximately $25 million.
Coal Supply Agreements
TEP is subject to fuel price risk from changes in the price of coal used to fuel its coal-fired generation facilities. Risk is mitigated by using long-term coal supply agreements with limited price movement. TEP's coal supply agreements expire in 2031. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Credit Risk
TEP is exposed to credit risk in energy-related marketing activities related to potential non-performance by counterparties. Risk of counterparty default is managed by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. Counterparty credit exposure is calculated by adding any outstanding receivable, net of amounts payable if a netting agreement exists, to the market value of any forward contracts. If exposure exceeds credit limits or contractual collateral thresholds, TEP may request that a counterparty provide credit enhancement in the form of cash collateral or an LOC.
TEP enters into short-term and long-term transactions related to wholesale marketing and natural gas hedging activities with various counterparties. As of December 31, 2023, TEP's total credit exposure was approximately $28 million including approximately $2 million of exposure to non-investment grade counterparties.
As of December 31, 2023, TEP had no cash posted as collateral to provide credit enhancement. As of December 31, 2023, TEP held no collateral from wholesale counterparties.
Interest Rate Risk
Credit Agreement
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under the 2021 Credit Agreement. In June 2023, TEP amended its credit agreement to provide for the transition to SOFR-based borrowings. Borrowings under the credit agreement are made at a rate based on either SOFR for the respective term plus an adjustment of 0.10% and an applicable margin, or ABR plus an applicable margin. TEP may experience significant volatility in variable interest rates paid on borrowings under its credit agreement.
The 2021 Credit Agreement provides for: (i) $250 million in revolving credit commitments; (ii) a $15 million swingline sublimit; and (iii) a $50 million LOC sublimit. The agreement matures in October 2026. As of December 31, 2023, TEP had no outstanding borrowings under its credit facility.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder and the Board of Directors of
Tucson Electric Power Company
Tucson, Arizona
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Tucson Electric Power Company and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, changes in stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements - Refer to Notes 1 and 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arizona Corporation Commission (the “ACC”) and Federal Energy Regulatory Commission (“FERC”). The ACC has jurisdiction with respect to the rates of electric distribution companies in Arizona. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. Accounting for the economics of rate regulation impacts multiple financial statement
line items and disclosures, such as utility plant; regulatory assets and liabilities; operating revenues; fuel expense; purchased power expense; operation and maintenance expense; and depreciation expense.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, (3) potential refunds to customers and (4) probability of potential charges related to the abandonment of regulated plants. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the regulatory authorities will not approve full recovery of the costs incurred. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the regulatory authorities included the following, among others:
•We evaluated the effectiveness of management’s controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory rate orders and settlements issued by the regulatory authorities for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the regulatory authorities’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the regulatory authorities and the filings with the regulatory authorities by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We inquired of management about utility plant that may be abandoned or retired early. We inspected the capital-projects budget and construction-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the regulatory authorities to identify any evidence that may contradict management’s assertion regarding recoverability of such costs.
•We inspected regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. For significant projects that were over budget or if full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance of such costs.
/s/ Deloitte & Touche LLP
Tempe, Arizona
February 8, 2024
We have served as the Company's auditor since 2017.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands)
Years Ended December 31,
2023 2022 2021
Operating Revenues $ 1,875,448 $ 1,808,082 $ 1,592,586
Operating Expenses
Fuel 372,692 504,757 399,914
Purchased Power 221,781 209,790 204,264
Transmission and Other PPFAC Recoverable Costs 81,706 84,323 65,583
Increase (Decrease) to Reflect PPFAC Recovery Treatment 80,207 (27,643) (64,155)
Total Fuel and Purchased Power 756,386 771,227 605,606
Operations and Maintenance 444,826 405,438 397,095
Depreciation 198,919 211,008 201,524
Amortization 36,876 40,045 43,995
Taxes Other Than Income Taxes 67,484 63,706 62,010
Total Operating Expenses 1,504,491 1,491,424 1,310,230
Operating Income 370,957 316,658 282,356
Other Income (Expense)
Interest Expense (95,389) (85,217) (86,865)
Allowance For Borrowed Funds 5,145 2,756 6,624
Allowance For Equity Funds 14,763 8,170 17,885
Unrealized Gains (Losses) on Investments 2,992 (7,094) 3,898
Other, Net 9,415 14,414 9,823
Total Other Income (Expense) (63,074) (66,971) (48,635)
Income Before Income Tax Expense 307,883 249,687 233,721
Income Tax Expense 49,229 32,262 32,476
Net Income $ 258,654 $ 217,425 $ 201,245
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Years Ended December 31,
2023 2022 2021
Cash Flows from Operating Activities
Net Income $ 258,654 $ 217,425 $ 201,245
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense 198,919 211,008 201,524
Amortization Expense 36,876 40,045 43,995
Amortization of Debt Issuance Costs 3,067 3,000 2,829
Use of Renewable Energy Credits for Compliance 45,416 44,762 45,815
Deferred Income Taxes 41,618 32,825 37,217
Pension and Other Postretirement Benefits Expense 15,241 12,207 15,342
Pension and Other Postretirement Benefits Funding (18,391) (17,818) (20,806)
Allowance for Equity Funds Used During Construction (14,763) (8,170) (17,885)
Change in Long-Term Regulatory Assets and Liabilities 3,615 55,522 17,190
Changes in Current Assets and Current Liabilities:
Accounts Receivable 95,724 (120,780) (18,738)
Materials, Supplies, and Fuel Inventory (19,381) (12,953) (18,445)
Regulatory Assets 62,827 (76,900) (59,542)
Other Current Assets (3,229) (2,205) 4,670
Accounts Payable and Accrued Charges (128,780) 132,796 14,979
Income Taxes Receivable/Payable - - (3,271)
Regulatory Liabilities (7,545) (2,615) (9,599)
Other, Net (10,317) 1,261 (8,466)
Net Cash Flows-Operating Activities 559,551 509,410 428,054
Cash Flows from Investing Activities
Capital Expenditures (577,766) (457,517) (499,405)
Purchase Intangibles, Renewable Energy Credits (62,444) (63,738) (55,297)
Other Investments 2,935 2,517 -
Contributions in Aid of Construction 4,252 8,131 5,678
Net Cash Flows-Investing Activities (633,023) (510,607) (549,024)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility - 5,000 50,000
Repayments of Borrowings, Revolving Credit Facility - (20,000) (35,000)
Proceeds from Issuance, Long-Term Debt-Net of Discount
373,954 323,804 322,231
Repayments of Long-Term Debt (240,745) (193,465) (250,000)
Dividends Paid to Parent (64,100) (100,000) (62,500)
Payment of Debt Issuance Costs (4,095) (3,012) (4,382)
Contributions from Parent - - 50,000
Other, Net 72 6,362 2,107
Net Cash Flows-Financing Activities 65,086 18,689 72,456
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash (8,386) 17,492 (48,514)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 50,981 33,489 82,003
Cash, Cash Equivalents, and Restricted Cash, End of Period $ 42,595 $ 50,981 $ 33,489
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
December 31,
2023 2022
ASSETS
Utility Plant
Plant in Service $ 8,035,444 $ 7,813,680
Construction Work in Progress 475,391 256,044
Total Utility Plant 8,510,835 8,069,724
Accumulated Depreciation and Amortization (2,570,157) (2,603,730)
Total Utility Plant, Net 5,940,678 5,465,994
Investments and Other Property 70,080 74,128
Current Assets
Cash and Cash Equivalents 8,616 16,237
Accounts Receivable (Net of Allowance for Credit Losses of $11,676 and $9,012)
217,381 320,899
Fuel Inventory 34,475 28,681
Materials and Supplies 172,667 155,650
Regulatory Assets 147,389 185,034
Derivative Instruments 3,091 27,019
Other 30,450 30,547
Total Current Assets 614,069 764,067
Regulatory and Other Assets
Regulatory Assets 182,997 184,894
Derivative Instruments 31,614 77,123
Other 134,196 123,575
Total Regulatory and Other Assets 348,807 385,592
Total Assets $ 6,973,634 $ 6,689,781
The accompanying notes are an integral part of these financial statements.
(Continued)
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
December 31,
2023 2022
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2023 and 2022)
$ 1,696,539 $ 1,696,539
Capital Stock Expense (6,357) (6,357)
Retained Earnings 1,162,921 968,367
Accumulated Other Comprehensive Loss (3,829) (2,884)
Total Common Stock Equity 2,849,274 2,655,665
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2023 and 2022)
- -
Long-Term Debt, Net 2,396,542 2,114,980
Total Capitalization 5,245,816 4,770,645
Current Liabilities
Current Maturities of Long-Term Debt, Net - 149,957
Accounts Payable 137,002 233,920
Accrued Taxes Other than Income Taxes 57,291 58,914
Accrued Employee Expenses 39,466 38,459
Accrued Interest 16,541 14,868
Regulatory Liabilities 92,740 110,782
Customer Deposits 15,833 14,073
Derivative Instruments 25,828 12,752
Other 36,312 49,163
Total Current Liabilities 421,013 682,888
Regulatory and Other Liabilities
Deferred Income Taxes, Net 647,730 590,926
Regulatory Liabilities 396,061 377,546
Pension and Other Postretirement Benefits 81,241 69,048
Derivative Instruments 4,338 4,787
Other 177,435 193,941
Total Regulatory and Other Liabilities 1,306,805 1,236,248
Commitments and Contingencies
Total Capitalization and Other Liabilities $ 6,973,634 $ 6,689,781
The accompanying notes are an integral part of these financial statements.
(Concluded)
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
(Amounts in thousands)
Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2020 $ 1,646,539 $ (6,357) $ 712,197 $ (10,942) $ 2,341,437
Net Income 201,245 201,245
Other Comprehensive Income(Loss), Net of Tax 1,027 1,027
Dividends Declared to Parent (62,500) (62,500)
Contribution from Parent 50,000 50,000
Balances as of December 31, 2021 $ 1,696,539 $ (6,357) $ 850,942 $ (9,915) $ 2,531,209
Net Income 217,425 217,425
Other Comprehensive Income(Loss), Net of Tax 7,031 7,031
Dividends Declared to Parent (100,000) (100,000)
Balances as of December 31, 2022 $ 1,696,539 $ (6,357) $ 968,367 $ (2,884) $ 2,655,665
Net Income 258,654 258,654
Other Comprehensive Income(Loss), Net of Tax (945) (945)
Dividends Declared to Parent (64,100) (64,100)
Balances as of December 31, 2023 $ 1,696,539 $ (6,357) $ 1,162,921 $ (3,829) $ 2,849,274
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 447,000 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 consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. TEP has reclassified the prior period’s amounts to conform with the current period presentation in the Consolidated Statements of Cash Flows to reclassify Change in Long-Term Regulatory Assets and Liabilities from Other, Net to a separately disclosed line. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows.
Accounting for Regulated Operations
TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates charged to retail customers or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters.
TEP applies regulatory accounting as the following conditions exist:
•an independent regulator sets rates;
•the regulator sets the rates to recover the specific enterprise’s costs of providing service; and
•rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers.
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 December 31, 2023, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED
The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) was adopted in 2023. Adoption of the new guidance had an insignificant impact on TEP's financial position, results of operations, cash flows, and disclosures.
Reference Rate Reform
In 2020, the FASB issued Accounting Standards Update (ASU) 2020-04 establishing Accounting Standards Codification (ASC) Topic 848, Reference Rate Reform, and in 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (collectively, ASC 848). ASC 848 contains practical expedients for reference rate reform-related activities that impact debt, leases, derivatives, and other contracts. The guidance in ASC 848 is optional and may be elected over time as reference rate reform activities occur. In 2022, the FASB issued ASU 2022-06, Deferral of the Sunset Date of Topic 848, to defer the sunset date of ASC 848 to December 31, 2024. ASU 2022-06 became effective immediately.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected in TEP’s financial statements. TEP is assessing the impact such guidance may have on TEP’s financial position, results of operations, cash flows, and disclosures.
Income Tax Disclosures
In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance should be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted.
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.
USE OF ACCOUNTING ESTIMATES
Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect:
•assets and liabilities in the balance sheet at the dates of the financial statements;
•disclosures about contingent assets and liabilities at the dates of the financial statements; and
•revenues and expenses in the income statement during the periods presented.
Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates.
Asset Retirement Obligations
TEP has identified legal AROs related to the retirement of certain assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP defers the accretion and depreciation expense associated with its legal AROs to a regulatory asset or liability account based on the ACC's approval of these costs in its depreciation rates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities.
Contingencies
Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable, and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these legal proceedings and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
CASH AND CASH EQUIVALENTS
TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
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 Consolidated Statements of Cash Flows:
Years Ended December 31,
(in millions) 2023 2022 2021
Cash and Cash Equivalents $ 9 $ 16 $ 10
Restricted Cash included in:
Investments and Other Property 24 22 20
Current Assets-Other 10 13 3
Total Cash, Cash Equivalents, and Restricted Cash $ 43 $ 51 $ 33
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.
ALLOWANCE FOR CREDIT LOSSES
TEP records an allowance for credit losses to reduce retail accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible.
INVENTORY
TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.
UTILITY PLANT
Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation facilities and transmission and distribution systems. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction.
The cost of repairs and maintenance, including planned generation facility overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred.
When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost net of removal costs and any salvage value. There is no impact to the income statement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
AFUDC and Capitalized Interest
AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.
The average AFUDC rates on regulated construction expenditures are included in the table below:
2023 2022 2021
Average AFUDC Rates 6.91 % 6.74 % 6.88 %
Depreciation
Depreciation is recorded for owned utility plant on a group method straight-line basis, excluding software intangible plant, at depreciation rates based on the economic lives of the assets, including estimates for salvage value and removal costs. The ACC approves depreciation rates for all generation facilities, distribution systems, and general plant assets. Transmission system assets are subject to the jurisdiction of the FERC.
Below are the average annual depreciation rates for all utility plant:
2023 2022 2021
Average Annual Depreciation Rates 3.01 % 3.24 % 3.30 %
Computer Software and Cloud Computing Costs
Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets-Other on the Consolidated Balance Sheets and amortized over three to five years. Amortization of implementation costs is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is impaired, the carrying value is reduced and recorded as an expense in the income statement.
EVALUATION OF ASSETS FOR IMPAIRMENT
Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time.
DEFERRED FINANCING COSTS
Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and filing costs.
TEP accounts for debt issuance costs related to credit facility arrangements as an asset.
The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the life of the original debt.
OPERATING REVENUES
TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved or market-based tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the due date past due and charges the customer a late payment fee, except during service disconnection moratoriums. No component of the transaction price is allocated to unsatisfied performance obligations.
TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which it expects to be entitled and recognizes a refund liability until it is certain it will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods.
LEASES
When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g. common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet.
TEP has operating leases for office facilities, land, rail cars, and communication tower space that are included in the balance sheet as follows:
December 31,
(in millions) 2023 2022
Lease Assets
Regulatory and Other Assets, Other $ 5 $ 6
Lease Liabilities
Current Liabilities, Other 1 1
Regulatory and Other Liabilities, Other 4 5
As of December 31, 2023, TEP's future minimum operating lease payments, excluding payments to lessors for variable costs, are $1 million or less in each year from 2024 through 2028 and $3 million thereafter.
PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE
TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities, and cost under-recoveries are deferred as regulatory assets.
RENEWABLE ENERGY CREDITS
The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power, or the REC purchase price, equals the REC cost recoverable through the RES tariff. As described above, the market cost of conventional power or contract price for power is recoverable through the PPFAC mechanism.
When RECs are purchased, TEP records the cost of the RECs, an indefinite-lived intangible asset, as other assets, and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and retail revenues in an equal amount. The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets-Other on
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the Consolidated Balance Sheets:
December 31,
(in millions) 2023 2022
Beginning of Period $ 82 $ 69
Purchased 57 58
Used for Compliance (45) (45)
End of Period $ 94 $ 82
TEP expenses the cost of internally developed RECs and PBI activity, which are not included in the table above. PBI costs are recoverable through the RES tariff.
PENSION AND OTHER POSTRETIREMENT BENEFITS
TEP sponsors noncontributory, defined benefit pension plans for substantially all employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees.
The Company recognizes an asset for a defined benefit plan's overfunded status or a liability for a plan's underfunded status in the balance sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement benefit plan. TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit costs, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers over the estimated service lives of employees.
Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations not yet recognized in the income statement are recognized as a component of AOCL since SERP expense is not currently recoverable in rates.
Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually.
FAIR VALUE
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able, and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
DERIVATIVE INSTRUMENTS
The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; and (ii) reduce exposure to energy commodity price volatility. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities in the balance sheet and are measured at fair value. The cash impacts of settled derivatives are recorded in Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity in the income statement.
For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TAXES OTHER THAN INCOME TAXES
TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
INCOME TAXES
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities in the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized.
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income.
Federal ITCs are deferred and amortized as a reduction to income tax expense over the life of the underlying asset. All other federal and state income tax credits, including PTCs, are treated as a reduction to income tax expense in the year the credit arises.
NOTE 2. REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.
RATE CASE MATTERS
2023 Rate Order
In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:
•a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;
•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% and an average cost of debt of 3.82%;
•a capital structure for rate making purposes of approximately 54% common equity and 46% long-term debt;
•approval to recover costs of changes in generation resources, including the addition of Oso Grande in rates; and
•denial of a request for a System Reliability Benefit adjustor that was designed to provide more timely recovery of TEP's energy resource investments.
In January 2023, the ACC ordered that funding for the just and equitable transition away from fossil fuel-based economies for communities impacted by early coal-fired plant closures be considered as part of the 2023 Rate Order. In the 2023 Rate Order, the ACC determined that there was insufficient evidence to support customer funding for the just and equitable transition as part of the proceeding.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
OTHER FERC MATTERS
In July 2023, TEP completed all compliance activities and submitted a final status update to the FERC related to the FERC's audit to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covered the period of January 1, 2018 to December 31, 2021. In 2023, TEP issued refunds to customers of $1 million related to the audit.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual approved costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period.
In 2022, the ACC approved a rate adjustment for the PPFAC that set the true-up component of the PPFAC rate to recover the then existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which contributed to under-collection of PPFAC costs. In May 2023, the ACC approved a rate adjustment for the PPFAC to collect the remaining uncollected balance over 12 months.
The table below summarizes the PPFAC regulatory asset (liability) balance:
Years Ended December 31,
(in millions) 2023 2022
Beginning of Period $ 124 $ 91
Deferred Fuel and Purchased Power Costs (1)
328 348
PPFAC and Base Power Recoveries (397) (315)
End of Period $ 55 $ 124
(1)Includes costs eligible for recovery through the PPFAC and base power rates.
Environmental Compliance Adjustor
The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided they are not already recovered in base rates or recovered through another commission-approved mechanism. Costs eligible for the ECA are subject to a cap equal to 0.5% of total annual retail revenue.
Tax Expense Adjustor Mechanism
The TEAM allows for the timely recovery of future significant income tax changes and provides TEP the ability to pass through as a kWh surcharge: (i) the change in EDIT compared to the test year; and (ii) the income tax effects of tax legislation that materially impacts TEP's authorized revenue requirement.
Transmission Cost Adjustor
The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. TEP files new TCA rates with
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the ACC in December each year based on changes in the FERC OATT formula rate. New TCA rates take effect in January of each year.
In December 2023, the ACC approved a revision to the TCA plan of administration to credit retail customers with transmission revenue associated with line losses from wholesale customers that take transmission service under TEP's OATT. The amendment, which reduces TEP's retail revenue, became effective in December 2023.
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 2023 was 13% of retail electric sales. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES tariff.
In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. In June 2023, the ACC approved TEP's extension of the 2021 RES implementation plan through 2024.
In 2023, the percentage of TEP's retail kWh sales attributable to the RES was approximately 22%, exceeding the overall 2023 RES requirement of 13%.
Energy Efficiency Standards
TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs 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. As of December 31, 2023, TEP's cumulative annual energy savings were approximately 27%.
In the 2023 Rate Order, the ACC approved a 2023 energy efficiency implementation plan with a cumulative three-year budget of $72 million, which is collected through the DSM surcharge. In January 2024, TEP filed a proposal with the ACC to refund over-collected, uncommitted DSM surcharge funds totaling $10 million over a period not to exceed one year beginning in May 2024.
2020 IRP Energy Efficiency Target
In 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP will report its savings for these years in its first integrated resource plan following 2025 and in TEP's periodic energy efficiency filings.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues based on an estimate of lost retail kWh sales during the period. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded in the Consolidated Balance Sheets are summarized in the table below:
Remaining Recovery Period (years) December 31,
($ in millions) 2023 2022
Regulatory Assets
Pension and Other Postretirement Benefits (Note 9)
Various $ 107 $ 90
Under Recovered Fuel and Purchased Energy Costs 1 55 124
Early Generation Retirement Costs Various 48 58
Lost Fixed Cost Recovery 1 35 25
Property Tax Deferrals (1)
1 30 29
Derivatives (Note 12)
6 26 3
Final Mine Reclamation and Retiree Healthcare Costs (2)
5 6 11
Income Taxes Recoverable through Future Rates (3)
Various 6 6
Unamortized Loss on Reacquired Debt Various 5 5
Other Regulatory Assets Various 12 19
Total Regulatory Assets 330 370
Less Current Portion 1 147 185
Total Non-Current Regulatory Assets $ 183 $ 185
Regulatory Liabilities
Income Taxes Payable through Future Rates (3)
Various $ 229 $ 244
Net Cost of Removal (4)
Various 130 43
Renewable Energy Standard Various 77 73
Derivatives (Note 12)
6 28 86
Demand Side Management 1 9 16
Deferred Investment Tax Credits Various 6 7
Transmission Balancing Accounts 1 5 9
Pension and Other Postretirement Benefits (Note 9)
Various 4 8
Transmission Revenue Subject to Refund - FERC 1 - 1
Other Regulatory Liabilities Various 1 2
Total Regulatory Liabilities 489 489
Less Current Portion 1 93 111
Total Non-Current Regulatory Liabilities $ 396 $ 378
(1)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes.
(2)Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in 2022.
(3)Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 13 for additional information regarding income taxes.
(4)Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Regulatory Assets and Liabilities
Except for Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Under Recovered Fuel and Purchased Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.
IMPACTS OF REGULATORY ACCOUNTING
If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.
NOTE 3. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Plant in Service on the Consolidated Balance Sheets by major class:
Annual Depreciation Rate (3)
Average Remaining Life in Years (3)
December 31,
($ in millions) 2023 2022
Plant in Service
Generation Plant 3.05% 22 $ 3,536 $ 3,491
Distribution Plant 2.61% 46 2,279 2,149
Transmission Plant 1.69% 33 1,323 1,295
General Plant 6.13% 9 685 653
Intangible Plant, Software Costs, and Other (1)
Various Various 201 224
Plant Held for Future Use - - 11 2
Total Plant in Service (2)
$ 8,035 $ 7,814
(1)Primarily represents computer software, which is being amortized over three to five years for smaller application software and 10 years for large enterprise software and has an average remaining life of three years.
(2)Includes plant acquisition adjustments of $(206) million as of December 31, 2023 and 2022.
(3)Based on the 2022 depreciation study available for the major classes of Plant in Service, effective September 1, 2023 as approved by the ACC as part of the 2023 Rate Order. TEP implemented new depreciation rates for Transmission Plant based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 2022 Final FERC Rate Order.
Accumulated Depreciation and Amortization
Depreciation Rates
As part of the 2023 Rate Order, effective September 2023, TEP reclassified $115 million from Accumulated Depreciation and Amortization to Regulatory and Other Liabilities-Regulatory Liabilities on the Consolidated Balance Sheets to reflect the impact of the revised depreciation rates on estimated cost of removal.
Amortization of Intangible Plant
Intangible Plant primarily consists of computer software. Accumulated amortization of computer software costs was $100 million and $110 million as of December 31, 2023 and 2022, respectively. Amortization of computer software costs totaled $27 million in 2023, $30 million in 2022, and $33 million in 2021. Future estimated amortization costs for existing computer software are $24 million in 2024, $19 million in 2025, $16 million in 2026, $11 million in 2027, and $7 million in 2028.
Intangible Plant includes $(4) million in acquisition discounts not subject to amortization as of December 31, 2023 and 2022.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
JOINTLY-OWNED FACILITIES
As of December 31, 2023, TEP was a participant in the following jointly-owned generation facilities and transmission systems:
($ in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value
Four Corners Units 4 and 5 7.0% $ 201 $ 4 $ (97) $ 108
Luna 33.3% 58 3 - 61
Gila River Unit 3 75.0% 218 17 (62) 173
Gila River Common Facilities 43.8% 78 1 (30) 49
Springerville Coal Handling Facilities 83.0% 208 - (103) 105
Springerville Common Facilities 86.0% 400 - (228) 172
Transmission Facilities Various 555 21 (236) 340
Total $ 1,718 $ 46 $ (756) $ 1,008
As a participant in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
ASSET RETIREMENT OBLIGATIONS
The liability accrual of AROs is primarily related to generation assets and is included in Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets:
December 31,
(in millions) 2023 2022
Beginning of Period $ 121 $ 139
Liabilities Incurred (1)
- 1
Liabilities Settled (2)
(2) (8)
Regulatory Deferral/Accretion Expense 3 5
Revisions to the Present Value of Estimated Cash Flows (3)
(8) (16)
End of Period $ 114 $ 121
(1)In 2022, TEP incurred an ARO for new photovoltaic generation placed in service.
(2)Primarily related to the retirement of Navajo and San Juan.
(3)Primarily related to revised decommissioning estimates for San Juan.
NOTE 4. REVENUE
TEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DISAGGREGATION OF REVENUES
The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service:
Years Ended December 31,
(in millions) 2023 2022 2021
Retail $ 1,283 $ 1,140 $ 1,088
Wholesale (1)
364 456 278
Other Services 124 104 114
Revenues from Contracts with Customers 1,771 1,700 1,480
Alternative Revenues 38 28 12
Other 66 80 101
Total Operating Revenues $ 1,875 $ 1,808 $ 1,593
(1)The decrease in 2023 was primarily due to decreases in volume and market prices.
Retail Revenues
TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during spring and summer months then decrease during fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances. See Note 5 for components of Accounts Receivable on the Consolidated Balance Sheets.
In August 2023, the ACC issued the 2023 Rate Order for new rates that took effect September 1, 2023. See Note 2 for more information regarding the 2023 Rate Order.
Wholesale Revenues
TEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand for capacity or the reading of meters for power. For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income.
Other Services Revenues
Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, reimbursement of various operating expenses for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities by the lessee of Springerville Unit 3, and miscellaneous service-related revenues.
Alternative Revenues
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR and ECA mechanisms, OATT and TCA balancing activity, and DSM performance incentive as alternative revenues. See Note 2 for additional information regarding these cost recovery mechanisms and performance incentive.
Other Revenues
Other Revenues include gains and losses on derivative contracts, asset management agreement optimization gains, common cost allocations to affiliates, and late and returned payment finance charges. See Note 6 for information regarding revenue from related parties and Note 12 for information regarding derivative instruments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 5. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable on the Consolidated Balance Sheets:
December 31,
(in millions) 2023 2022
Retail $ 109 $ 87
Retail, Unbilled 57 46
Retail, Allowance for Credit Losses (12) (9)
Wholesale (1)
37 132
Due from Affiliates (Note 6)
7 26
Other 19 39
Accounts Receivable $ 217 $ 321
(1)Includes $10 million and $52 million as of December 31, 2023 and 2022, respectively, of receivables related to revenue from derivative instruments.
ALLOWANCE FOR CREDIT LOSSES
TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Consolidated Balance Sheets:
Years Ended December 31,
(in millions) 2023 2022
Beginning of Period $ (9) $ (10)
Credit Loss Expense (7) (5)
Write-offs 4 6
End of Period $ (12) $ (9)
Customer Payment Assistance
In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $15 million DES payment assistance funds in the year ended December 31, 2022. Funds received directly reduced Accounts Receivable on the Consolidated Balance Sheets.
NOTE 6. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets:
December 31,
(in millions) 2023 2022
Receivables from Related Parties
UNS Electric $ 5 $ 22
UNS Gas 2 2
UNS Energy - 2
Total Due from Related Parties $ 7 $ 26
Payables to Related Parties
UNS Energy $ 1 $ 1
UNS Electric 1 5
UNS Gas 1 1
Total Due to Related Parties $ 3 $ 7
The following table presents the components of related party transactions included in the Consolidated Statements of Income:
Years Ended December 31,
(in millions) 2023 2022 2021
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)
$ 8 $ 5 $ 11
Wholesale Revenues, UNS Electric (1)(2)
39 50 25
Control Area Services, UNS Electric (3)
2 3 6
Common Costs, UNS Energy Affiliates (4)
23 22 21
Goods and Services Provided by Affiliates to TEP
Purchased Power, UNS Electric (1)
2 2 1
Corporate Services, UNS Energy (5)
8 8 7
Corporate Services, UNS Energy Affiliates (6)
1 1 3
Capacity Charges, UNS Gas (7)
2 1 -
(1)TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT.
(2)In 2022, TEP began charging UNS Electric for power purchased in the EIM on behalf of UNS Electric.
(3)TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement.
(4)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.
(5)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 $7 million in each of 2023 and 2022, and $6 million in 2021.
(6)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
(7)UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 7. DEBT AND CREDIT AGREEMENT
DEBT
Long-term debt matures more than one year from the date of debt issuance. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets:
December 31,
($ in millions) Interest Rate Maturity Date 2023 2022
Notes
2012 Senior Notes 3.85% 2023 $ - $ 150
2015 Senior Notes (1)
3.05% 2025 300 300
2020 Senior Notes 1.50% 2030 300 300
2022 Senior Notes 3.25% 2032 325 325
2014 Senior Notes 5.00% 2044 150 150
2018 Senior Notes 4.85% 2048 300 300
2020 Senior Notes 4.00% 2050 350 350
2021 Senior Notes 3.25% 2051 325 325
2023 Senior Notes 5.50% 2053 375 -
Tax-Exempt Local Furnishings Bonds
2013 Pima A 4.00% 2029 - 91
Total Long-Term Debt (2)
2,425 2,291
Less Unamortized Discount and Debt Issuance Costs 28 26
Less Current Maturities of Long-Term Debt - 150
Total Long-Term Debt, Net $ 2,397 $ 2,115
(1)On December 15, 2024, the 2015 Senior Notes become callable at par plus accrued interest. The notes mature on March 15, 2025.
(2)As of December 31, 2023 and 2022, all of TEP's debt is unsecured.
Debt Issuances and Redemptions
In February 2023, TEP issued and sold $375 million aggregate principal amount of 5.50% senior unsecured notes due April 2053. TEP may redeem the notes prior to October 15, 2052, with a make-whole premium plus accrued interest. On or after October 15, 2052, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem and repay debt in March 2023 and for general corporate purposes.
In March 2023, TEP repaid at maturity $150 million aggregate principal amount of 3.85% senior unsecured notes.
In March 2023, TEP redeemed at par prior to maturity $91 million aggregate principal amount of tax-exempt bonds bearing interest at a rate of 4.00% per annum.
In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt in March 2022 and June 2022 and for general corporate purposes.
In March 2022, TEP redeemed at par prior to maturity $177 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.
In June 2022, TEP redeemed at par prior to maturity $16 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Maturities
Long-term debt matures on the following dates:
($ in millions) Long-Term Debt (1)
2024 $ -
2025 300
2026 -
2027 -
2028 -
Thereafter 2,125
Total $ 2,425
(1)Total long-term debt excludes $19 million of related unamortized debt issuance costs and $9 million of unamortized original issue discount.
CREDIT AGREEMENT
In October 2021, TEP entered into an unsecured credit agreement that provides for revolving credit commitments with swingline and LOC sublimits, due in October 2026, the termination date (2021 Credit Agreement). The final maturity date is subject to two one-year extensions if certain conditions are satisfied. Amounts borrowed are recorded in Borrowings Under Credit Agreement on the Consolidated Balance Sheets.
•Amounts borrowed under the 2021 Credit Agreement are used for working capital and other general corporate purposes.
•Interest rates and fees are based on a pricing grid tied to TEP's credit rating.
LOCs are issued from time to time to support energy procurement, hedging transactions, and other business activities. In June 2023, the 2021 Credit Agreement was amended to provide for the transition to SOFR-based borrowings.
Terms are as follows:
Sub-Limit Swingline(1)
Sub-Limit LOC Weighted Average Interest Rate
Capacity Borrowed(2)
Available Pricing(3)
($ in millions) December 31, 2023
Agreement $ 250 $ 15 $ 50 $ - $ 250 - % SOFR+ADJ 0.10%+1.025% or ABR+0.025%
($ in millions) December 31, 2022
Agreement $ 250 $ 15 $ 50 $ 5 $ 245 - % LIBOR+1.025% or ABR+0.025%
(1)ABR pricing would apply to swingline loans.
(2)Includes a $5 million LOC at a rate of 1.025% per annum as of December 31, 2022, which was cancelled in August 2023.
(3)TEP's pricing 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 February 8, 2024, there was $235 million available under the 2021 Credit Agreement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 8. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As of December 31, 2023, TEP had the following commitments:
(in millions) 2024 2025 2026 2027 2028 Thereafter Total
Minimum Purchase Commitments
Fuel, Including Transportation $ 68 $ 67 $ 63 $ 63 $ 54 $ 226 $ 541
Purchased Power 26 4 - - - - 30
Transmission 28 26 9 1 1 2 67
Purchase Commitments
Renewable Power Purchase Agreements and Other 84 84 79 79 79 689 1,094
RES Performance-Based Incentives 7 5 5 4 4 15 40
Total Commitments $ 213 $ 186 $ 156 $ 147 $ 138 $ 932 $ 1,772
Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of renewable PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.
Minimum Purchase Commitments
Fuel, Including Transportation
TEP has long-term agreements for the purchase and delivery of coal with various expiration dates through 2031. In 2023, TEP entered into a coal transportation agreement for Springerville Unit 1 and Unit 2 through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs.
TEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2024 and 2048. In 2023, TEP amended and extended an agreement for gas transportation to Gila River through 2029 and amended and extended an agreement for gas transportation to Sundt through 2048.
Purchased Power
TEP has contracts for purchased power to: (i) meet system load and energy requirements; (ii) replace generation from company-owned units under maintenance and during outages; and (iii) meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the third quarter of 2025. Certain of these contracts are at a fixed price per MWh and others are indexed to market prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2023.
Transmission
TEP has long-term firm point-to-point contracts to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2024 and 2030.
Purchase Commitments
Renewable Power Purchase Agreements
TEP enters into long-term renewable PPAs, which require TEP to purchase 100% of certain renewable energy generation facilities' output and RECs associated with the output delivered once commercial operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2051.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RES Performance-Based Incentives
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2024 and 2034.
EPC Agreement
In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I at a cost of $294 million. TEP will own and operate the facility, which will be located in southeast Tucson and have a nominal capacity rating of 200 MW and storage capacity of 800 MWh. Roadrunner Reserve I is expected to be placed in service in the second half of 2025. As of December 31, 2023, TEP has made payments of $90 million in connection with the construction and development of Roadrunner Reserve I.
CONTINGENCIES
Legal Matters
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.
Mine Reclamation at Generation Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.
TEP is liable for a portion of final mine reclamation costs for the mines at San Juan and Four Corners. TEP's share of final mine reclamation costs at Four Corners is $6 million upon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the coal supply agreement in 2022. As of December 31, 2023, TEP's remaining final mine reclamation liability at San Juan was $25 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. For additional information see Note 1, Restricted Cash, and Note 3, Plant in Service. TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation totaled $29 million and $37 million as of December 31, 2023 and 2022, respectively, and was recorded in Other on the Consolidated Balance Sheets.
Performance Guarantees
TEP has joint generation participation agreements with participants at Four Corners and 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 December 31, 2023, 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Environmental Matters
TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.
NOTE 9. EMPLOYEE BENEFITS PLANS
PENSION BENEFIT PLANS
TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under IRS regulations. TEP also maintains a SERP for executive management.
OTHER POSTRETIREMENT BENEFITS PLAN
TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.
TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $2 million in each of 2023 and 2022 and $3 million in 2021. Other postretirement benefits for unclassified employees are self-funded.
REGULATORY RECOVERY
TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in AOCL since SERP expense is not currently recoverable in rates.
The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet:
Pension Benefits Other Postretirement Benefits
December 31,
(in millions) 2023 2022 2023 2022
Regulatory Assets $ 107 $ 90 $ - $ -
Regulatory Liabilities - - (4) (8)
Regulatory and Other Assets-Other - 8 - -
Accrued Employee Expenses (1) (1) (3) (2)
Pension and Other Postretirement Benefits (28) (20) (53) (49)
Accumulated Other Comprehensive Loss 5 4 - -
Net Amount Recognized $ 83 $ 81 $ (60) $ (59)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
OBLIGATIONS AND FUNDED STATUS
The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2023 and 2022. The table below presents the status of all TEP pension and other postretirement benefit plans.
Pension Benefits Other Postretirement Benefits
Years Ended December 31,
(in millions) 2023 2022 2023 2022
Change in Benefit Obligation
Beginning of Period $ 411 $ 600 $ 74 $ 90
Actuarial Loss (Gain) 39 (176) 6 (17)
Interest Cost 22 16 4 2
Service Cost 12 21 4 5
Benefits Paid (23) (35) (5) (6)
Plan Amendments (1)
- 1 - -
Settlements (2)
- (16) - -
End of Period (3)
461 411 83 74
Change in Fair Value of Plan Assets
Beginning of Period 398 538 23 28
Actual Return on Plan Assets 44 (101) 4 (4)
Benefits Paid (22) (34) (2) (3)
Employer Contributions (4)
12 11 2 2
Settlements (2)
- (16) - -
End of Period (5)
432 398 27 23
Funded Status at End of Period $ (29) $ (13) $ (56) $ (51)
(1)Employees promoted to officer become eligible for SERP benefits based in part on their service prior to officer promotion. These prior service costs are accounted for in this table as a plan amendment.
(2)Represents the aggregate lump-sum benefit payments for plans that exceeded the threshold of service plus interest costs. The change is due to a decrease in retiring employees opting to receive their benefits as a lump-sum.
(3)The increase in pension and other postretirement benefit obligations was primarily due to a decrease in the discount rate.
(4)TEP expects to contribute $11 million to the pension plans and $2 million to the VEBA trust in 2024.
(5)The increase in pension and other postretirement benefit plan assets was primarily due to positive equity and fixed income returns.
All three pension plans had a projected benefit obligation in excess of plan assets as of December 31, 2023, compared to one as of December 31, 2022. This was primarily due to a decrease in discount rates partially offset by positive equity and fixed income returns. For plans with projected benefit obligations in excess of plan assets, total projected benefit obligations and plan assets were $461 million and $432 million, respectively, as of December 31, 2023, and $21 million and none, respectively, as of December 31, 2022.
The other postretirement benefits plan had an accumulated postretirement benefit obligation in excess of the fair value of plan assets as of December 31, 2023 and 2022.
The accumulated benefit obligation aggregated for all pension plans was $409 million and $373 million as of December 31, 2023 and 2022, respectively. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2023 and 2022. The following table includes information for the pension plan with an accumulated benefit obligation in excess of pension plan assets:
December 31,
(in millions) 2023 2022
Accumulated Benefit Obligation $ 20 $ 19
Fair Value of Plan Assets - -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table provides the components of TEP’s regulatory assets, regulatory liabilities, and AOCL that have not been recognized as components of net periodic benefit cost as of the dates presented:
Pension Benefits Other Postretirement Benefits
December 31,
(in millions) 2023 2022 2023 2022
Net Loss (Gain) $ 111 $ 93 $ (3) $ (7)
Prior Service Cost (Benefit) 1 1 (1) (1)
The Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components:
Pension Benefits Other Postretirement Benefits
Years Ended December 31,
(in millions) 2023 2022 2021 2023 2022 2021
Service Cost $ 12 $ 21 $ 20 $ 4 $ 5 $ 6
Non-Service Cost
Interest Cost 22 16 14 4 2 2
Expected Return on Plan Assets (29) (37) (34) (2) (1) (2)
Prior Service Benefit Amortization - - - - (1) -
Amortization of Net Loss 5 7 9 - - 1
Effect of Settlement - 3 - - - -
Net Periodic Benefit Cost $ 10 $ 10 $ 9 $ 6 $ 5 $ 7
The non-service components of net periodic benefit cost are primarily included in Other, Net on the Consolidated Statements of Income. In 2022, $3 million of the effect of settlement was deferred as a regulatory asset and recorded in Regulatory and Other Assets-Regulatory Assets on the Consolidated Balance Sheets. TEP capitalized 21% of service cost as a cost of construction in each of 2023 and 2022, and 22% in 2021.
The changes in plan assets and benefit obligations recognized as regulatory assets, regulatory liabilities, or in AOCL were as follows:
Pension Benefits Other Postretirement Benefits
Regulatory Asset AOCL Regulatory Asset/Liability
(in millions) 2023 2022 2021 2023 2022 2021 2023 2022 2021
Current Year Actuarial Loss (Gain) $ 22 $ (27) $ (16) $ 1 $ (9) $ - $ 4 $ (11) $ (13)
Prior Service Benefit Amortization - - - - - - - 1 -
Amortization of Net Loss (5) (6) (8) - (1) (1) - - (1)
Prior Service Cost - - - - 1 - - - -
Effect of Settlement - (3) - - - - - - -
Total Recognized Loss (Gain) $ 17 $ (36) $ (24) $ 1 $ (9) $ (1) $ 4 $ (10) $ (14)
For all pension plans, TEP amortizes prior service costs and benefits on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.
Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time regarding these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.
TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table includes the weighted average assumptions used to determine benefit obligations:
Pension Benefits Other Postretirement Benefits
2023 2022 2023 2022
Discount Rate 5.4% 5.7% 5.2% 5.6%
Rate of Compensation Increase 3.2% 2.9% N/A N/A
The following table includes the weighted average assumptions used to determine net periodic benefit costs:
Pension Benefits Other Postretirement Benefits
2023 2022 2021 2023 2022 2021
Discount Rate, Service Cost 5.9% 3.4% 3.3% 5.7% 3.2% 2.9%
Discount Rate, Interest Cost 5.6% 2.7% 2.3% 5.5% 2.5% 1.9%
Rate of Compensation Increase 2.9% 2.8% 2.8% N/A N/A N/A
Expected Return on Plan Assets 7.5% 7.0% 6.8% 7.5% 7.0% 7.0%
Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:
December 31,
2023 2022
Next Year (Pre-65) 7.3% 7.0%
Next Year (Post-65) 5.8% 6.0%
Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5%
Year Ultimate Rate is Reached (Pre-65) 2034 2032
Year Ultimate Rate is Reached (Post-65) 2028 2028
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS
TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows:
Pension Other Postretirement Benefits
2023 2022 2023 2022
Asset Category
Equity Securities 53 % 53 % 60 % 61 %
Fixed Income Securities 40 % 39 % 38 % 38 %
Real Estate 6 % 7 % - % - %
Other 1 % 1 % 2 % 1 %
Total 100 % 100 % 100 % 100 %
As of December 31, 2023, the fair value of VEBA trust assets was $27 million, of which $10 million were fixed income investments and $17 million were equities. As of December 31, 2022, the fair value of VEBA trust assets was $23 million, of which $9 million were fixed income investments and $14 million were equities. The VEBA trust assets are primarily Level 1 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy:
Level 1 Level 2 Level 3 Total
(in millions) December 31, 2023
Asset Category
Cash Equivalents $ 3 $ - $ - $ 3
Equity Securities:
United States Large Cap - 68 - 68
United States Small Cap - 26 - 26
Non-United States - 68 - 68
Global - 67 - 67
Fixed Income - 171 - 171
Real Estate - - 27 27
Private Equity - - 2 2
Total $ 3 $ 400 $ 29 $ 432
(in millions) December 31, 2022
Asset Category
Equity Securities:
United States Large Cap $ - $ 61 $ - $ 61
United States Small Cap - 23 - 23
Non-United States - 66 - 66
Global - 61 - 61
Fixed Income - 154 - 154
Real Estate - - 30 30
Private Equity - - 3 3
Total $ - $ 365 $ 33 $ 398
•Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
•Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
•Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of comparable properties.
•Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
(in millions) Private Equity Real Estate Total
Balance as of December 31, 2021 $ 4 $ 26 $ 30
Actual Return on Plan Assets:
Assets Held at Reporting Date - 4 4
Purchases, Sales, and Settlements (1) - (1)
Balance as of December 31, 2022 3 30 33
Actual Return on Plan Assets:
Assets Held at Reporting Date (1) (3) (4)
Purchases, Sales, and Settlements - - -
Balance as of December 31, 2023 $ 2 $ 27 $ 29
Pension Plan Investments
Investment Goals
Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.
Risk Management
TEP recognizes the difficulty of achieving investment objectives considering the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
Relationship between Plan Assets and Benefit Obligations
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data but will be no less frequent than annually via actuarial valuation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Target Allocation Percentages
The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced:
Pension Other Postretirement Benefits
December 31, 2023
Cash/Treasury Bills 2% 1%
Equity Securities:
United States Large Cap 16% 25%
United States Mid Cap -% 8%
United States Small Cap 6% 4%
Non-United States Developed -% 15%
Non-United States Emerging -% 8%
Global Equity 28% -%
Global Infrastructure 3% -%
Fixed Income 38% 39%
Real Estate 6% -%
Private Equity 1% -%
Total 100% 100%
Pension Fund Descriptions
For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-party funds.
ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate:
(in millions) 2024 2025 2026 2027 2028 2029-2033
Pension Benefits $ 26 $ 27 $ 27 $ 28 $ 29 $ 159
Other Postretirement Benefits 6 6 6 6 6 31
DEFINED CONTRIBUTION PLAN
TEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $8 million in 2023 and $7 million in each of 2022 and 2021.
NOTE 10. SHARE-BASED COMPENSATION
2020 FORTIS RESTRICTED STOCK UNIT PLAN
The Fortis Board of Directors ratified the 2020 Restricted Stock Unit Plan (2020 Plan) effective January 2020. Under the 2020 Plan, executive officers of Fortis and its subsidiaries may be granted time-based RSUs annually, which may be settled in cash or shares. Each RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table represents RSUs awarded by Fortis for UNS Energy:
2023 2022 2021
RSUs 26,980 17,996 20,794
The awards are initially classified as liability awards because: (i) executive officers have the option to elect the cash or share settlement feature; and (ii) this election is contingent on an event within the executive officers' control. The liability awards may be reclassified as equity awards if the executive officers elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $2 million as of December 31, 2023 and 2022.
TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $1 million in 2023 and no compensation expense in 2022 and 2021, based on its share of Fortis' compensation expense.
2015 SHARE UNIT PLAN
The Human Resources and Governance Committee of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (2015 Plan) effective January 2015. Under the 2015 Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of PSUs and RSUs annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur.
The following table represents PSUs and RSUs awarded by UNS Energy:
2023 2022 2021
PSUs 58,237 40,793 44,931
RSUs (1)
2,146 2,409 2,401
(1)Effective January 2020, executive officer RSU awards are issued through the 2020 Plan. Certain key employees will continue to be awarded RSUs through the 2015 Plan.
The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $6 million and $4 million as of December 31, 2023 and 2022, respectively.
TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $3 million in 2023, $2 million in 2022, and $4 million in 2021 based on its share of UNS Energy's compensation expense.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS
Years Ended December 31,
(in millions) 2023 2022 2021
Interest Paid, Net of Amounts Capitalized $ 85 $ 80 $ 76
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:
Years Ended December 31,
(in millions) 2023 2022 2021
Net Cost of Removal Increase (Decrease) (1)
$ 91 $ (49) $ (41)
Accrued Capital Expenditures 38 26 38
Renewable Energy Credits 3 3 3
Asset Retirement Obligations Increase (Decrease) (2)
(5) (30) 34
(1)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.
(2)TEP retired the San Juan asset retirement cost asset, concurrent with the retirement of San Juan Unit 1 in June 2022.
NOTE 12. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.
FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:
Level 1 Level 2 Total
(in millions) 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions) December 31, 2022
Assets
Restricted Cash (1)
$ 35 $ - $ 35
Energy Derivative Contracts, Regulatory Recovery (2)
- 100 100
Energy Derivative Contracts, No Regulatory Recovery (2)
- 4 4
Total Assets 35 104 139
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
- (18) (18)
Total Liabilities - (18) (18)
Total Assets (Liabilities), Net $ 35 $ 86 $ 121
(1)Restricted Cash represents amounts held in money market funds, which approximate fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets-Other on the 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 Consolidated Balance Sheets.
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis 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 (1)
(in millions) December 31, 2023
Derivative Assets
Energy Derivative Contracts $ 35 $ 15 $ - $ 20
Derivative Liabilities
Energy Derivative Contracts (30) (15) - (15)
(in millions) December 31, 2022
Derivative Assets
Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76
Derivative Liabilities
Energy Derivative Contracts (18) (14) - (4)
(1)TEP records cash collateral received related to energy derivative contracts in Current Liabilities-Other on the Consolidated Balance Sheets. As of February 8, 2024, TEP held no cash received as collateral to provide credit enhancement.
DERIVATIVE INSTRUMENTS
TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers.
TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or liability in the balance sheet:
Years Ended December 31,
(in millions) 2023 2022 2021
Unrealized Net Gain (Loss) (1)
$ (81) $ 72 $ 62
(1)For the year ended December 31, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas. For the years ended December 31, 2022 and 2021, unrealized net gain on regulatory recoverable derivative contracts was primarily due to increases in forward market prices of natural gas.
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income:
Years Ended December 31,
(in millions) 2023 2022 2021
Operating Revenues $ 18 $ 11 $ 7
Derivative Volumes
As of December 31, 2023, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:
December 31,
2023 2022
Power Contracts GWh 1,449 1,979
Gas Contracts BBtu 89,105 96,755
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.
TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to individual contracts.
The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $28 million as of December 31, 2023, compared with $86 million as of December 31, 2022. As of December 31, 2023, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features had been triggered on December 31, 2023, TEP would have been required to post $28 million of collateral. As of December 31, 2023, TEP had $13 million in outstanding net payable balances for settled positions.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt:
Net Carrying Value Fair Value
Fair Value Hierarchy December 31,
(in millions) 2023 2022 2023 2022
Liabilities
Long-Term Debt, including Current Maturities Level 2 $ 2,397 $ 2,265 $ 2,127 $ 1,901
NOTE 13. INCOME TAXES
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% to pre-tax income due to the following:
Years Ended December 31,
(in millions) 2023 2022 2021
Federal Income Tax Expense at Statutory Rate $ 65 $ 52 $ 49
State Income Tax Expense, Net of Federal Deduction 12 10 9
Federal/State Tax Credits (1)
(17) (22) (10)
Allowance for Equity Funds Used During Construction (3) (1) (3)
Excess Deferred Income Taxes (8) (10) (14)
Other - 3 1
Total Income Tax Expense $ 49 $ 32 $ 32
(1) TEP realized PTC benefits of $15 million in 2023, $19 million in 2022, and $7 million in 2021, related to Oso Grande being placed in service in May 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Tax Expense included on the Consolidated Statements of Income consists of the following:
Years Ended December 31,
(in millions) 2023 2022 2021
Current Income Tax Expense
Federal $ 7 $ (1) $ (2)
State 1 - -
Total Current Income Tax Expense 8 (1) (2)
Deferred Income Tax Expense
Federal 31 26 27
Federal Investment Tax Credits (2) (1) (1)
State 12 8 8
Total Deferred Income Tax Expense 41 33 34
Total Income Tax Expense $ 49 $ 32 $ 32
In 2018, the ACC Refund Order was approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $8 million, $10 million, and $14 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2023, 2022, and 2021, respectively. TEP's TEAM allows income tax changes that materially affect TEP’s authorized revenue requirement, including changes in EDIT amortization, to be shared with customers. Effective January 1, 2021, TEP shares any changes in its EDIT amortization through the usage-based adjustor.
The significant components of deferred income tax assets and liabilities consist of the following:
December 31,
(in millions) 2023 2022
Gross Deferred Income Tax Assets
Customer Advances and Contributions in Aid of Construction $ 22 $ 22
Federal General Business Credits (1)
55 61
Income Taxes Payable Through Future Rates 57 60
Other 95 103
Total Gross Deferred Income Tax Assets 229 246
Gross Deferred Income Tax Liabilities
Plant, Net (793) (735)
PPFAC (14) (31)
Plant Abandonments (11) (14)
Pensions (21) (20)
Income Taxes Recoverable Through Future Rates (1) (1)
Other (37) (36)
Total Gross Deferred Income Tax Liabilities (877) (837)
Deferred Income Taxes, Net $ (648) $ (591)
(1) Includes ITC and PTC carryovers.
TEP recorded no valuation allowance against tax credit and net operating loss carryforward deferred income tax assets as of December 31, 2023 and 2022. Management believes TEP will produce sufficient taxable income in the future to realize credit and loss carryforwards before they expire.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
As of December 31, 2023, TEP had the following carryforward amounts:
($ in millions) Amount Expiring Year
State Credits $ 9 2024 - 29
Federal Investment Tax Credits 12 2037 - 43
Federal Production Tax Credits 42 2041 - 43
Other Federal Credits 1 2037 - 43
TEP recorded no interest expense in 2023 and 2022 related to uncertain tax positions. In addition, TEP had no interest payable, and no penalties accrued as of December 31, 2023 and 2022.
TEP has been audited by the IRS through tax year 2010. TEP's 2014 to 2022 tax years are open for audit by federal and state tax agencies.
Included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets are current income taxes receivable and payable that are due from and to affiliates, respectively. TEP had no intercompany income taxes receivable or payable as of December 31, 2023, and a receivable of $1 million as of December 31, 2022.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures were effective as of December 31, 2023.
Management’s Report on Internal Control Over Financial Reporting
TEP’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of TEP’s internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations Internal Control - Integrated Framework.
Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2023, TEP’s internal control over financial reporting was effective.
Changes in Internal Control Over Financial Reporting
There has been no change in TEP’s internal control over financial reporting during the fourth quarter of 2023 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Pre-Approved Policies and Procedures
Rules adopted by the SEC in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. UNS Energy’s Audit and Risk Committee has adopted a policy pursuant to which audit, audit-related, tax, and other services are pre-approved by category of service. Recognizing that situations may arise where it is in the Company’s best interest for the auditor to perform services in addition to the annual audit of the Company’s financial statements, the policy sets forth guidelines and procedures with respect to approval of the four categories of service designed to achieve the continued independence of the auditor when it is retained to perform such services for UNS Energy. The policy requires the Audit and Risk Committee to be informed of each service and does not include any delegation of the Audit and Risk Committee’s responsibilities to management. The Audit and Risk Committee may delegate to the Chair of the Audit and Risk Committee the authority to grant pre-approvals of audit and non-audit services requiring Audit and Risk Committee approval where the Audit and Risk Committee Chair believes it is desirable to pre-approve such services prior to the next regularly scheduled Audit and Risk Committee meeting. The decisions of the Audit and Risk Committee Chair to pre-approve any such services from one regularly scheduled Audit Committee meeting to the next shall be reported to the Audit and Risk Committee.
Fees
The Audit and Risk Committee has considered whether the provision of services to TEP by Deloitte & Touche LLP, Public Company Accounting Oversight Board (United States) PCAOB ID No. 34 (Deloitte), beyond those rendered in connection with their audit and review of TEP’s financial statements, is compatible with maintaining their independence as auditor.
The following table details principal accountant fees paid to Deloitte for professional services:
(in thousands) 2023 2022
Audit Fees (1)
$ 1,170 $ 1,181
Audit-Related Fees (2)
106 105
Total $ 1,276 $ 1,286
(1)Audit Fees includes fees billed, or expected to be billed, by Deloitte, for professional services for the financial statement audits of TEP's consolidated financial statements included in its Annual Report on Form 10-K and review services of TEP's consolidated financial statements included in its Quarterly Reports on Form 10-Q. Audit Fees also includes services provided by Deloitte in
connection with comfort letters, consents, and other services related to SEC matters, financing transactions, and statutory and regulatory audits.
(2)Audit-Related Fees are fees billed, or expected to be billed, by Deloitte for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above. The fees are for additional procedures for nonrecurring material transactions in 2023.
All services performed by our principal accountant are approved in advance by the Audit and Risk Committee in accordance with the Audit and Risk Committee’s pre-approval policy for services provided by the Independent Registered Public Accounting Firm.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Page
(a) (1) Consolidated Financial Statements as of December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statement of Changes in Stockholder’s Equity
Notes to Consolidated Financial Statements
(2) Financial Statement Schedule
All schedules have been omitted because they are either not applicable, not required, or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.
(3) Exhibits
Reference is made to the Exhibit Index commencing on page 80.