EDGAR 10-K Filing

Company CIK: 100122
Filing Year: 2021
Filename: 100122_10-K_2021_0000100122-21-000005.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 128 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 433,000 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 which is a leader in the North American electric and gas utility business.
Regulated Utility Operations
TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for coal, natural gas, wind, and solar generation resources 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 utility accounting practices and rates of TEP, 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
Prior to August 2019, TEP had stated transmission rates. In August 2019, the FERC approved TEP's proposed forward-looking OATT formula rate, which updates annually and allows for timely recovery of transmission related costs. TEP's OATT formula rate is currently subject to refund following hearing and settlement procedures.
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 (Retail Rates).
The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, 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 supply an increasing percentage of their retail sales from renewable generation sources each year until renewable retail sales represent at least 15% by 2025. The RES also requires that DG account for 30% of the renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP currently plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG.
In 2020, the percentage of retail kWh sales attributable to the RES was approximately 16%, exceeding the 2020 requirement of 10%.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K and Rates and Regulations below for additional information regarding RES.
Energy Efficiency Standard
Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of December 31, 2020, TEP’s cumulative annual energy savings was approximately 22%.
RES requirements and Energy Efficiency Standards may be impacted by changes to Arizona's energy policy. 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.
ACC Rates
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. Retail Rates are generally established in rate case proceedings. TEP's last rate case proceeding was finalized in 2020.
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.
•REST - a usage-based charge that recovers the cost of complying with the RES.
•DSM - a usage-based charge that recovers the cost of energy efficiency programs that are designed to help TEP comply 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 stations to comply with environmental regulations.
•TEAM - a usage-based charge or credit that allows TEP to pass-through the regulatory deferral balance related to the TCJA, the change in EDIT, and any material income tax effects of post-test year tax legislation.
•TCA - a usage-based charge or credit that allows TEP to recover the cost or return the benefit of investments and expenses resulting from annual updates to 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 2020 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) 2020 2019 2018 2017 2016
Electric Sales
Residential 4,170 28 % 3,698 22 % 3,766 24 % 3,786 29 % 3,724 29 %
Commercial 2,005 13 % 2,077 13 % 2,136 14 % 2,192 17 % 2,139 17 %
Industrial, non-Mining 1,834 12 % 1,896 11 % 1,949 12 % 1,939 15 % 2,006 16 %
Industrial, Mining 1,086 7 % 1,057 6 % 1,033 7 % 991 8 % 997 8 %
Other 16 - % 16 - % 16 - % 18 - % 30 - %
Total Retail Sales by Customer Class 9,111 61 % 8,744 53 % 8,900 57 % 8,926 68 % 8,896 70 %
Wholesale Sales, Long-Term 508 4 % 490 3 % 424 3 % 587 4 % 463 4 %
Wholesale Sales, Short-Term (1)
5,279 35 % 7,257 44 % 6,279 40 % 3,630 28 % 3,308 26 %
Total Electric Sales 14,898 100 % 16,491 100 % 15,603 100 % 13,143 100 % 12,667 100 %
Average Number of Retail Customers
Residential 391,953 90 % 387,409 90 % 384,021 90 % 381,399 90 % 378,991 90 %
Commercial 39,096 9 % 38,838 9 % 38,642 9 % 38,564 9 % 38,403 9 %
Industrial, non-Mining 491 - % 503 - % 504 - % 520 - % 580 - %
Industrial, Mining 4 - % 4 - % 4 - % 4 - % 4 - %
Other 1,877 1 % 1,872 1 % 1,873 1 % 1,879 1 % 1,866 1 %
Total Retail Customers 433,421 100 % 428,626 100 % 425,044 100 % 422,366 100 % 419,844 100 %
(1)Sales increased in 2019 and 2018 due to an increase in generation capacity related to Gila River Unit 2. In 2020, sales decreased due to the retirement of Navajo in 2019 and Gila River Unit 2 replacing the generation to serve retail load.
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 2021 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 2020 was 9,111 GWh, which is an increase of 2% from 2016 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. However, due to stay at home orders and the adoption of work from home practices, there was an offsetting increase in energy usage by residential customers.
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 COVID-19 pandemic impacts.
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 2022
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 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 our 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.
Energy Imbalance Market
In 2019, TEP signed an agreement with the California Independent System Operator indicating its intent to begin participating in the EIM by spring of 2022. Participation in the EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the EIM, TEP must demonstrate resource adequacy through a combination of owned or contracted resources. TEP's participation in the EIM is expected to: (i) reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance 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.
In 2018, the ACC opened a docket to evaluate several energy policies including retail competition for generation services. In 2019, the ACC staff prepared a draft of retail electric competition rules and workshops have been held on the subject. Such rules have not been officially proposed and no changes have been made. The adoption of new rules would be subject to rulemaking proceedings at the ACC. TEP cannot predict what additional steps, if any, the ACC may take to further evaluate retail competition in this docket.
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, 2020, TEP had 2,932 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 2 Gila Bend, AZ 2003 550 SRP 100 550
Gila River 3 Gila Bend, AZ 2003 550 SRP 75.0 413
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)
1-10 Tucson, AZ 2019-2020 188 TEP 100 188
Sundt Internal Combustion Turbines Tucson, AZ 1972-1973 50 TEP 100 50
DeMoss Petrie 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 (2)
2 Springerville, AZ 1990 406 TEP 100 406
San Juan 1 Farmington, NM 1976 340 PNM 50.0 170
Four Corners 4 Farmington, NM 1969 785 APS 7.0 55
Four Corners 5 Farmington, NM 1970 785 APS 7.0 55
Renewables
Utility-Scale Renewables (3)
Various 2002-2017 42 TEP 100 42
Total Capacity 2,932
(1)TEP placed in service five natural gas RICE units in December 2019 and an additional five units in March 2020. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the RICE units.
(2)Springerville Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.
(3)In September 2020, Sundt Areva Solar Thermal was retired. Sundt Areva Solar Thermal had a nominal capacity of 5 MW.
Springerville
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, compensates TEP for operating the facilities and pays an allocated portion of the fixed costs related to the Springerville Common Facilities and Springerville Coal Handling Facilities. SRP, the owner of Springerville Unit 4, owns 17.05% of the Springerville Coal Handling Facilities and 14% of the Springerville Common Facilities.
Utility-Scale Renewables
As of December 31, 2020, TEP owned 42 MW of PV solar generation capacity, measured in AC. The following table presents TEP's owned utility-scale 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
Springerville Solar Springerville, AZ 2004-2014 14
UASTP Phase I & II (2)
Tucson, AZ 2010-2011 6
Solon Prairie Fire (2)
Tucson, AZ 2012 4
Raptor Ridge Tucson, AZ 2021 10
Wind
Oso Grande (3)
Chaves County, NM 2021 250
Total Capacity 42 260
(1)TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.
(2)The UASTP I & II and Solon Prairie Fire are located on properties held under land easements and leases.
(3)Oso Grande is expected to be placed in service in the first half of 2021.
Renewable Power Purchase Agreements
As of December 31, 2020, TEP had renewable PPAs for 156 MW from solar resources and 80 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
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
E.On Tech Park Tucson, AZ 2012 5
Gato Montes Tucson, AZ 2012 5
Small PPAs (<5MW) Various Various 5
Wilmot Solar (1)
Sahuarita, AZ 2021 100
Wind
Macho Springs Deming, NM 2011 50
Red Horse Wind Willcox, AZ 2015 30
Borderlands Wind Catron County, NM 2021 99
Total Capacity 236 199
(1)Wilmot Solar will be accompanied by 30 MW of battery storage.
Public Utility Regulatory Policies Act Ruling
On December 17, 2019, the ACC issued a decision related to contract terms for qualifying facilities under Public Utility Regulatory Policies Act (PURPA). Congress enacted PURPA in 1978 in response to a national energy crisis. The FERC prescribes rules for the implementation of PURPA and state regulatory agencies implement PURPA. PURPA requires, among other things, that electric utilities enter into contracts to purchase power from facilities that qualify under PURPA at a price
equivalent to the utility's avoided cost. The ACC's 2019 decision requires, among other things, that TEP's contracts to purchase power from qualifying facilities with renewable nameplate capacity over 100 kW include certain terms and conditions, including a minimum 18-year contract length and pricing based on TEP's long-term avoided cost.
PURPA and the FERC's regulations limit qualifying facilities to a power production capacity of 80 MW. In September 2020, the FERC issued a ruling that identified energy storage facilities as separate production facilities that are not to be identified as limiting elements on qualifying facilities' output in order to keep the net production capacity below the qualifying threshold.
The rulings did not have a material impact on TEP's operations or financial results.
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 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K 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. Certain of these contracts are at a fixed price per MWh and others are indexed to natural gas prices. 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 amount of reserves TEP is required to carry.
Peak Demand and Future Resources
Peak Demand
(in MW) 2020 2019 2018 2017 2016
Retail Customers 2,467 2,367 2,413 2,415 2,278
In 2020, 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. Retail peak demand in years 2017 to 2020 was higher than in 2016 primarily due to warmer than normal summer temperatures.
Forecasted retail peak demand for 2021 is 2,295 MW compared with actual peak demand of 2,467 MW in 2020. TEP’s 2021 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 2021.
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 June 2020, TEP filed its 2020 IRP, which outlines its plan over the next 15 years to meet its electric demand while transitioning to a more sustainable energy portfolio. The plan includes a goal to reduce carbon emissions by 80% compared to 2005 by 2035. The IRP proposes to achieve this goal by reducing our dependency on coal-fired generation over the next 12 years while developing new renewable energy projects like Oso Grande, Raptor Ridge, and energy storage projects to meet electric demand. Over the past five years, TEP's generation capacity from coal-fired generation has decreased by 24%.
In December 2020, ACC staff issued a NOPR based on energy rules it had proposed in November 2020. If adopted, the new rules would require affected utilities to, among other things, reduce carbon emissions by 50% below a baseline level by 2032 and 100% by 2050. The new rules are not expected to have a material impact on TEP's 2020 IRP.
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 2020 IRP and the NOPR.
Fuel Supply
A summary of Fuel and Purchased Power resource information is provided below:
Average Cost (cents per kWh) Percentage of Total kWh Resources
2020 2019 2018 2020 2019 2018
Coal 2.51 2.46 2.44 38 % 41 % 44 %
Natural Gas 2.03 2.33 2.54 49 % 45 % 42 %
Purchased Power, Non-Renewable 6.26 4.09 4.32 9 % 10 % 10 %
Purchased Power, Renewable 9.42 9.43 9.41 4 % 4 % 4 %
100 % 100 % 100 %
Coal Supply
The coal used for generation is low-sulfur, bituminous or sub-bituminous coal sourced from mines in Arizona and New Mexico. The table below provides information on the existing coal contracts that supply our generation stations. The average cost of coal per MMBtu, including transportation, was $2.37 in 2020 and 2019, and $2.33 in 2018.
Station Coal Supplier 2020 Coal Consumption (tons in 000s) Contract Expiration Date Average Sulfur Content Coal Obtained From
Springerville Peabody CoalSales 2,420 2022 1.0% Lee Ranch Mine/El Segundo Mine
Four Corners NTEC 297 2031 0.7% Navajo Mine
San Juan San Juan Coal Co. 631 2022 0.8% San Juan Mine
Coal-Fired Generation Facilities Operated by TEP
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' estimated remaining life.
Coal-Fired Generation Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generation facilities at Four Corners and San Juan. Four Corners, which is operated by APS, and San Juan, which is operated by PNM, are mine-mouth generation facilities located adjacent to the coal reserves. TEP expects coal reserves available to these two jointly-owned generation facilities to be sufficient for the remaining lives of the stations.
Natural Gas Supply
The table below provides information on the natural gas transportation agreements that deliver our natural gas to the generation stations. The average cost of natural gas per MMBtu, including transportation, was $2.19 in 2020, $2.20 in 2019, and $2.92 in 2018.
Station Natural Gas Transportation Counterparty Contract Expiration Date(s)
Gila Transwestern Pipeline Co./El Paso Natural Gas Company, LLC 2022-2040
Luna El Paso Natural Gas Company, LLC 2022
Sundt (1)
El Paso Natural Gas Company, LLC 2023-2040
DeMoss Petrie Southwest Gas Corporation Retail Tariff
North Loop Southwest Gas Corporation Retail Tariff
(1)TEP placed in service five natural gas RICE units at Sundt in December 2019 and an additional five units in March 2020. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the RICE units.
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) Indian Nations. TEP's transmission and distribution systems included approximately 2,197 miles of transmission lines and 7,797 miles of distribution lines as of December 31, 2020.
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 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 added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its 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, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects the recovery of the cost of environmental compliance through Retail Rates.
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. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.
National Ambient Air Quality Standards
In December 2020, the EPA published a final rule retaining the current primary and secondary U.S. National Ambient Air Quality Standards (NAAQS) for ozone (O3), which was set at 70 parts per billion (ppb) by the EPA in 2015. If an area does not meet the standard, the area is designated as a “non-attainment” area and the state must develop a plan to bring the air-shed into compliance. A “non-attainment” designation under the ozone NAAQS may slow economic growth in the region, increase restrictions on ozone precursor emissions of volatile organic compounds and nitrogen oxides from existing sources and impact TEP's ability to site new local fossil fuel generation. Under the 70 ppb standard, Arizona submitted recommendations for area designations (attainment, non-attainment, or unclassifiable) to the EPA in September 2016. The EPA completed all area designations as of July 2018. Maricopa County, the location of Gila River, was designated as "non-attainment." There is no significant impact on Gila River from this designation at this time. Pima County, the location of the Sundt, DeMoss Petrie and North Loop generation stations, and Apache County, the location of Springerville, are currently in attainment with the 70 ppb standard.
HUMAN CAPITAL
As of December 31, 2020, TEP had 1,575 employees, of which approximately 648 were represented by the International Brotherhood of Electrical Workers Local No. 1116 (IBEW). The current collective bargaining agreements between the IBEW and TEP expire in July 2022 with wages in effect through December 2022.
TEP values its employees and recognizes that the framework for success within the company is dependent on a strong workforce who feels safe, supported, and empowered. TEP strives to create a positive environment for its employees through the values and initiatives outlined below.
Governance and Culture
TEP believes that the foundation for a healthy work environment starts with the tone at the top. The Executive Officers and Board of Directors are actively involved in tracking the Company's goals and objectives. TEP's business strategy is intended to help employees thrive through a commitment to building adaptability 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 retaliation, discrimination, harassment, or abusing 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. Based on its commitment to diversity, equity, and inclusion, TEP implemented unconscious bias training for all employees, and conducted workshops to encourage employees to think inclusively. TEP continues to identify and focus on behaviors that build strong and positive relationships at work to support an environment of thriving employees.
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.
•Women in Energy - dedicated to: (i) inspiring women in their professional growth; (ii) developing leadership qualities; and (iii) promoting engagement in diverse thought.
Workforce Development Pipeline Planning
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) underserved and minority students, 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, 2020, 12% 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, 2021, are as follows:
Name Age Position(s) Held Executive Officer Since
Susan M. Gray (1)
48 President and Chief Executive Officer (2)
Frank P. Marino (1)
56 Senior Vice President and Chief Financial Officer 2013
Todd C. Hixon (1)
54 Senior Vice President, General Counsel and Corporate Secretary 2011
Erik B. Bakken 48 Vice President, System Operations and Energy Resources 2018
Dallas J. Dukes 53 Vice President, Energy Programs and Pricing 2019
Cynthia A. Garcia 53 Vice President, Energy Delivery 2020
Mark C. Mansfield 65 Vice President, Special Projects 2012
Catherine E. Ries 61 Vice President, Customer and Human Resources 2007
Michael E. Sheehan 53 Vice President, Resource Planning, Fuels, and Wholesale Marketing 2020
Mary Jo Smith 63 Vice President and Policy Advisor 2015
Morgan C. Stoll 50 Vice President and Chief Information Officer 2016
Martha B. Pritz 59 Treasurer 2017
(1)Member of the TEP 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.
(2)Susan M. Gray was appointed Chief Executive Officer, effective January 1, 2021, succeeding David G. Hutchens.
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 reduce power consumption. These technologies include renewable energy, customer-sited DG, appliances, equipment, energy storage, 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 2016 through 2020.
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 typically 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 typically limited by relatively mild winter weather in TEP's retail service territory. 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 will depend heavily on wind conditions. 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 11% of total revenues in 2020. 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 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 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 that 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, such as 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. New initiatives or changes to existing requirements could arise in the future through legislative, regulatory, or other initiatives (including ballot initiatives) on either a federal or state level.
In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various state energy policies, including renewable energy goals and retail competition for generation services. In December 2020, ACC staff issued a NOPR based on energy rules it had proposed in November 2020. If adopted, the new rules would require Arizona regulated utilities to, among other things: (i) reduce their CO2 emissions by 50% by 2032, 75% by 2040, and by 100% by 2050, measured from a baseline emissions period of 2016 through 2018; (ii) reach certain levels of distributed energy storage and demand-side energy resources; and (iii) follow updated integrated resource planning rules. These draft rules, if adopted during a formal rule-making proceeding, may accelerate the Company's long-term resource diversification strategy and increase capital expenditures and operating expenses. TEP's ability to recover costs, including its investments, associated with these and other 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. In 2019 and 2020, the ACC staff discussed draft rules for retail competition for generation services. These rules have not been officially proposed, but if such rules were adopted, retail competition could have a negative impact on the Company's retail sales. TEP cannot predict the final outcome of these proposals. The adoption of any new policies or rules would be subject to rulemaking proceedings at the ACC.
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 greenhouse gases, water use, wastewater discharges, solid waste, hazardous waste, and management of CCR.
These laws and regulations can contribute to higher capital, operating, and other costs, particularly with regard to 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. Failure to comply with applicable laws and regulations may result in litigation, the imposition of fines, penalties, and a requirement 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, San Juan, and Four Corners, coupled with the financial impact of future climate change legislation, other environmental regulations, 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 closure 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 be closed before the end of their useful lives in response to economic conditions and/or changes in regulation, including the ACC's draft energy rules and future changes in environmental regulations. If any of the 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, 2020, the net book value of TEP's in service coal-fired generation facilities was $1,169 million.
Volatility or disruptions 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.
We rely on access to bank markets 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 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 and counterparties we do business with, unprecedented volatility in the markets, and general economic downturns in TEP's utility service territories. 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 facilities. In addition, changing market conditions could 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.
Generation facility closings or changes in power flows into TEP's service territory could require us to redeem or defease some or all of the tax-exempt bonds issued for the Company's benefit, which could result in increased financing costs.
TEP has financed a portion of utility plant assets with the proceeds of pollution control revenue bonds and industrial development revenue bonds issued by governmental authorities. Interest on these bonds is, subject to certain exceptions, excluded from gross income for federal tax purposes. This tax-exempt status is based, in part, on continued use of the assets for pollution control purposes or the local furnishing of power within TEP’s two-county retail service area.
As of December 31, 2020, there were outstanding approximately $177 million aggregate principal amount of tax-exempt bonds that financed pollution control expenditures at Springerville. The bonds may be redeemed at par commencing in the first quarter of 2022. The bonds would be subject to early redemption should Springerville be retired and dismantled prior to maturity or the first redemption date.
In addition, as of December 31, 2020, there were outstanding approximately $107 million aggregate principal amount of tax-exempt bonds that financed local furnishing facilities. Depending on changes that may occur to the regional generation mix in the desert southwest, to the regional bulk transmission network, or to the demand for retail power in TEP’s local service area, it is possible that TEP would no longer qualify as a local furnisher of power within the meaning of the Internal Revenue Code. If TEP could no longer qualify as a local furnisher of power, all of TEP’s tax-exempt local furnishing bonds could be subject to mandatory early redemption by TEP or defeasance to the earliest redemption date, and TEP could be required to pay additional amounts if interest on such bonds were no longer tax-exempt. The bonds may be redeemed at par commencing on dates ranging from the second quarter of 2022 to the first quarter of 2023.
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, weather, and other hazards, interruption of fuel supply, and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failures or other complications, occur from time to time. They are an inherent risk of the Company's business and can cause damage to its reputation. If TEP’s generation facilities or transmission and distribution systems operate below expectations, TEP’s operating results could be negatively affected 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 Indian 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 Indian 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 of the 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 may impact regional and global weather conditions and result in extreme weather events, including high temperatures, severe thunderstorms, drought, and wildfires. Changes in weather conditions or extreme weather events in TEP’s service territory or affecting TEP's remote generation facilities or transmission system may lead to service outages and business interruptions, which could result in an increase in capital expenditures and operating expenses. Any increases in severity and frequency of weather-related system outages could affect TEP's operations and system reliability. Although physical utility assets have been constructed and are operated and maintained to withstand severe weather, there can be no assurance that they will successfully do so in all circumstances. In addition, changes in weather conditions or extreme weather events outside of TEP's service territory could result in higher wholesale energy prices, insurance premiums, and other costs, which could negatively impact TEP's business and operations. Any of these situations could have a negative impact on 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 facilities are critical to the provision of electric service to our customers and provide the framework for our service infrastructure. TEP is facing a heightened risk of physical attacks on the Company's electric systems. 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 its network infrastructure, which is part of an interconnected regional 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. TEP and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to disrupt operations. Despite implementation of security measures, there can be no assurance that the Company will be able to prevent the disruption of our operations.
If, despite TEP's security measures, a significant physical attack occurred, the Company could: (i) have operations disrupted 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. The Company relies on the continued operation of sophisticated digital information technology systems and network infrastructure, which are part of an interconnected regional grid. TEP's operations technology systems face a heightened risk of cyber-attack due to the critical nature of the infrastructure, the Company's connectivity to the Internet, and inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, and other types of data security breaches.
TEP's information technology systems and network infrastructure have been subject, 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 or to disrupt utility operations through computer viruses and phishing attempts either directly or indirectly through its material vendors or related third parties. Furthermore, the Company's utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.
If, despite TEP's security measures, a significant cyber or data breach occurred, the Company could: (i) have operations disrupted, customer information stolen, and general business system and process interruption or compromise, including preventing TEP from servicing customers, collecting revenues or the 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. To date we have not experienced any material breaches or disruptions to our network, information systems, or our service operations.
The widespread outbreak of an illness or any other communicable disease, or any other public health crisis, including the COVID-19 pandemic, could adversely affect our business, results of operations and financial condition.
TEP could be negatively impacted by the widespread outbreak of an illness or any other communicable disease, or any other public health crisis that results in economic and trade disruptions, including the disruption of global supply chains. The COVID-19 pandemic has negatively impacted the economy on a global, national, and local level, disrupted global supply chains, and created significant volatility and disruption of financial markets. Responses from governmental authorities and companies to reduce the spread of the COVID-19 pandemic have significantly reduced economic activity through various containment measures including, among others, business closures, work stoppages or work-from-home orders, shuttering of public spaces and events, and/or severe restrictions of global and regional travel.
The extent of the impact of the COVID-19 pandemic on TEP’s operational and financial performance, including the ability to execute business strategies and initiatives in the expected time frame, the ability to obtain external financing, and the timing of regulatory actions, will depend on factors beyond our control, including the duration, spread, and severity of the pandemic, and how quickly and to what extent normal economic and operating conditions resume, all of which are uncertain and cannot be predicted at this time. An extended period of global supply chain and economic disruption could materially affect TEP’s business, results of operations, access to sources of liquidity, and financial condition.
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.

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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 is owned by TEP and located in Tucson, Arizona. 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, individually and in conjunction with PNM, acquired land rights, land easements, and leases for San Juan's generation facilities, transmission lines, and water diversion facility located on land owned by 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 Indian Nations;
•possible inability of TEP to legally enforce its rights against adverse claims and the Indian Nations without Congressional consent; or
•failure or inability of the Indian 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 in the future and renewal action by the applicable tribal or federal agencies will be required. The ultimate cost of renewal for certain of the rights-of-way for the Company's transmission lines is uncertain. The principal owned and leased 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. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP.
See Note 9 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. SELECTED FINANCIAL DATA
The Company is not providing information responsive to this Item as it is choosing to voluntary comply with the revisions to Item 6 of Form 10-K contained in SEC Release No. 33-10890, which eliminated the disclosure requirements contained in Item 301 of Regulation S-K.

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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: (i) capital expenditures; and (ii) environmental matters;
•critical accounting policies and estimates; and
•new accounting standards issued and 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 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 activity and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K can be found in Part II, Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations of our 2019 Annual Report on Form 10-K.
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 at the front of this report and Part I, Item 1A. Risk Factors for additional information.
References in this discussion and analysis to "we" and "our" are to TEP.
OUTLOOK AND STRATEGIES
TEP's 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 and regulations; 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; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe, affordable, and reliable service.
•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 2020, we announced our long-term goal to reduce carbon emissions by exiting coal-fired generation over the next 12 years and increasing renewable energy resources and energy storage. 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.
CURRENT ECONOMIC CONDITIONS-COVID-19
In March 2020, the World Health Organization declared COVID-19 a pandemic. In response to the COVID-19 pandemic, Arizona's governor and many local governments issued various requirements and recommendations, and further actions may continue to be taken. This pandemic has caused changes in consumer and business behavior and disrupted economic activity in TEP’s service territory. These disruptions could continue for a prolonged period of time or become more severe. We activated our business continuity plans and continue to reevaluate and reassess protocols and plans as the pandemic conditions evolve. These actions are intended to aid in the prevention of the spread of COVID-19 among our employees and customers, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Actions we have taken include: (i) implemented work from home practices for a portion of our workforce; (ii) increased precautions with regard
to employee and facility hygiene for field crews and others who must continue working on premises, including elimination of in-person meetings and separation of field crews; (iii) imposed travel limitations on employees; (iv) implemented screening procedures conducted prior to entering our facilities; (v) distributed face masks to our workforce; and (vi) restricted access to critical facilities. Additional safety protocols have been implemented for work required within customers' premises that are intended to aid in the protection of our employees, our customers, and the community.
Recognizing the potential effect that the COVID-19 pandemic could have on many customers’ ability to pay their bills and the need for continued utility service, we voluntarily suspended service disconnections and late fees for non-payment of bills until December 31, 2020. In addition, the ACC approved our request to refund customers approximately $8 million of over-collected DSM funds in excess of program expenditures. Funds were returned to customers in the form of bill credits over the June 2020 billing cycle. In December 2020, the ACC enacted a bill credit and payment program for residential electric customers who are behind on their electric bills as a result of the COVID-19 pandemic. We are also working with our suppliers, vendors, and contractors to assess and mitigate potential impacts to the procurement of goods and services.
The COVID-19 pandemic remains a continuously evolving situation. We cannot predict the duration of the pandemic or the ultimate effects of it on the global, national, or local economy. We will continue to monitor developments affecting our workforce, customers, suppliers, and operations and take additional measures as we believe are warranted. We have not experienced a material impact to our results of operations as a result of the COVID-19 pandemic.
Performance - 2020 Compared with 2019
TEP reported net income of $191 million in 2020 compared with $187 million in 2019. The increase of $4 million, or 2%, was primarily due to:
•$21 million in higher retail revenue primarily due to an increase in usage related to favorable weather;
•$11 million in higher LFCR revenues; and
•$9 million in higher AFUDC due to an increase in construction projects and a FERC Order that provided for an adjustment in the AFUDC calculation.
The increase was partially offset by:
•$18 million in higher depreciation and amortization expense due to an increase in asset base;
•$9 million in higher interest expense primarily related to long-term debt issuances in 2020; partially offset by lower interest expense related to the Springerville Common Facilities finance leases;
•$4 million in higher income tax expense primarily due to AMT credits recognized in 2019 not recurring in 2020; and
•$4 million decrease in value of investments used to support certain post-employment benefits as a result of less favorable market conditions.
FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to the potential economic impacts of the COVID-19 pandemic, regulatory matters, generation resource shift, and weather patterns.
COVID-19 Pandemic Impacts
The extent of the impact of the COVID-19 pandemic on our operational and financial performance depends on certain developments, including: (i) the duration of the declared health emergencies; (ii) actions by governmental authorities and regulators; (iii) impacts on our customers, employees, and vendors; and (iv) actions by us to assist our customers through this crisis. These developments are continuously evolving and are challenging to predict. Areas currently impacted, and areas we expect to continue to be impacted, may have an effect on our results of operations, cash flows, and earnings are noted below.
Retail Sales
As a result of various Executive Orders issued in 2020 by Arizona's governor and changes in consumer and business behavior in response to the COVID-19 pandemic, energy usage by our commercial and industrial customers has decreased below average levels experienced in prior periods. This decrease is expected to last for the duration of the pandemic response and may continue beyond as a result of sustained economic impacts in our service territory. However, energy usage by our residential customers has increased due to stay at home orders and widespread adoption of work from home practices. We expect the
increase to last for the duration of the pandemic response and possibly beyond as companies rethink their work from home practices. In 2020, we did not experience a significant impact to total retail sales as a result of the COVID-19 pandemic.
Retail Customer Assistance
We suspended service disconnections and late fees for all customers who would have otherwise been eligible for service disconnection to help customers affected by the COVID-19 pandemic beginning March 2020 through December 31, 2020. During 2020, we experienced an increase in accounts receivable balances greater than 90 days as a result of the suspension of service disconnections and higher summer bills due to warmer weather.
In December 2020, the ACC enacted a bill credit and payment program for residential customers who are behind on their electric bills as a result of the COVID-19 pandemic. For qualifying customers, the program included: (i) an upfront bill credit applied to their December 2020 bill; and (ii) automatic enrollment into an eight-month payment plan. We also voluntarily created payment arrangements for commercial customers.
As a result of the moratoriums, we increased our credit loss reserve by $7 million as of December 31, 2020, compared to December 31, 2019. We are continuing to monitor collection activity and will adjust our allowance for credit losses as needed.
Reduction to DSM Surcharge
In April 2020, we filed a request with the ACC to refund to customers approximately $8 million of over-collected DSM funds. In May 2020, the ACC approved the request and we returned the funds in the form of customer bill credits over the June 2020 billing cycle.
Regulatory Matters
We are subject to comprehensive regulation. The discussion below contains material developments to those matters.
2020 Rate Order
In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.
Provisions of the 2020 Rate Order include, but are not limited to:
•a non-fuel retail revenue increase of $58 million over test year retail revenues;
•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%;
•a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;
•approval to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;
•a TEAM that will be updated for income tax changes that materially affect our authorized revenue requirement; and
•a TCA mechanism, updated annually, allowing us to recover changes in transmission costs approved by the FERC.
In addition, the 2020 Rate Order established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In January 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. TEP cannot predict the timing or outcome of these proceedings.
2019 FERC Rate Case
In 2019, the FERC issued an order approving our proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings.
Provisions of the order include, but are not limited to:
•replacing our stated transmission rates with a forward-looking formula rate;
•a 10.4% return on equity; and
•elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.
The requested forward-looking formula rate is intended to allow for a more timely recovery of transmission-related costs. If this request is approved, transmission revenues would increase by approximately $7 million annually. As part of the order, the FERC established hearing and settlement procedures. On February 8, 2021, the Settlement Judge determined that the parties in the rate case proceeding were at an impasse and recommended ending the settlement process and appointing a Presiding Judge to continue the formula rate case proceeding. All rates charged under the revised OATT pursuant to the FERC order are subject to refund until the proceeding concludes. We reserved $15 million as of December 31, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities-Regulatory Liabilities on the Consolidated Balance Sheets. We cannot predict the outcome of the proceedings.
Other FERC Matters
On January 29, 2021, the FERC notified TEP that it is commencing an audit that is intended to evaluate our 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 will cover the period of January 1, 2018 to the present. We cannot predict the outcome or findings, if any, of the FERC audit at this time.
Federal Income Tax Legislation
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC issued the ACC Refund Order, which was based on the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that would be trued-up annually for actual results. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts were deferred to a regulatory liability or asset and were used to adjust the following year's bill credit amounts.
Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The refund amounts totaled $35 million in 2020 and $33 million in both 2019 and 2018. The refunds were returned to customers through a combination of a customer bill credit and a regulatory liability. In 2020, the customer bill credit accounted for 50% of the returned savings.
In December 2020, the ACC approved the TEAM as part of the 2020 Rate Order. In 2021, through the initial TEAM rate, TEP will return the amounts previously deferred to a regulatory liability.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 and Liquidity and Capital Resources, Income Tax Position of this Form 10-K for additional information regarding the ACC Refund Order.
Federal Energy Regulatory Commission
In 2018, the FERC issued the FERC Refund Order. In May 2018, we responded to the order and the FERC approved our proposal of an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, to be effective March 21, 2018. As a result, we recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
Also in 2018, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization. In November 2019, the FERC issued a final rule on the NOPR, which required us to address the effect of the TCJA and related EDIT amortization in our next FERC rate case. As required by the final rule, our 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the FERC Refund Order.
Generation Resource Shift
Our long-term strategy is to continue our shift from carbon-intensive sources to a more sustainable energy portfolio including expanding renewable energy resources while reducing reliance on coal-fired generation resources. In June 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.
2020 IRP
Our 2020 IRP proposal includes a goal of reducing our carbon dioxide emissions 80% compared to levels in 2005 by 2035. To achieve this goal, we plan to continue the retirement of older fossil-fuel resources and replace these assets with a combination of renewable resources, battery storage, and energy efficiency programs. The existing coal-fired generation fleet faces a number of uncertainties impacting 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, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we plan exiting all ownership interests in coal generation facilities over the next 12 years. 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 IRP proposal is dependent on obtaining regulatory recovery approval.
We are planning to provide more than 70% of our power from wind and solar resources as part of a cleaner energy portfolio. The Oso Grande project is expected to provide a significant shift towards renewable generation and further decrease TEP's dependency on coal-fired generation. Our generation capacity from coal-fired generation has decreased by 24% in the past five years.
Arizona Energy Policy
In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy and energy efficiency goals, integrated resource planning, and retail competition for generation services. In 2019 and 2020, the ACC discussed draft rules related to retail electric competition. The ACC discussed those draft rules during workshops, but such rules have not been officially proposed and no changes have been made.
In December 2020, ACC staff issued a NOPR based on energy rules it had proposed in November 2020. If adopted, the new rules would require TEP to: (i) reduce carbon emissions below a baseline level by 50% by 2032 and 100% by 2050; (ii) include a demand-side resource capacity of at least 35% of our 2020 peak demand by 2030; (iii) achieve on average 1.3% annual energy efficiency savings starting in 2021; and (iv) install energy storage systems with an aggregate capacity equal to at least 5% of TEP's 2020 peak demand. The new rules would repeal the existing RES and EE Standards. We would seek the ACC's approval to recover any costs related to new energy policies or requirements. We cannot predict the outcome of these matters or their impact on our financial position or results of operations.
Navajo Generating Station
TEP and the co-owners of Navajo retired the generation station in November 2019 and began decommissioning activities. We expect the majority of decommissioning activities to be completed by 2024 with monitoring activities continuing through 2054. We have historically recovered the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, we received approval to recover final retirement costs over a 10-year period in the 2020 Rate Order.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the early retirement of Navajo.
Sundt Generating Station
In 2018, the Pima County Department of Environmental Quality approved our air permit which allowed us to place in service 10 natural gas RICE units at Sundt and required the retirement of Sundt Units 1 and 2 in November 2019. We have historically recovered the capital and operating costs in base rates using useful lives of 2028 and 2030 of Sundt Units 1 and 2, respectively. Due to the early retirement, we received approval to recover final retirement costs over a 10-year period as part of the 2020 Rate Order.
We placed in service five of the RICE units in December 2019, and the remaining five were placed in service in March 2020. The Sundt RICE units balance the variability of intermittent renewable energy resources. The units replaced 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which were less efficient and lacked the quick start, fast ramp capabilities of the Sundt RICE units. We received approval to recover the 10 Sundt RICE units over the useful lives of the assets as part of the 2020 Rate Order. The total cost of the Sundt RICE units project was $187 million.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the early retirement of Sundt Units 1 and 2.
Gila River Generating Station
In 2017, we entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three-year option to purchase the unit. We completed the purchase of Gila River Unit 2 in December 2019 for $165 million. The 550 MW of capacity, power, and ancillary services replaced coal-fired generation lost due to early retirements. The ACC approved recovery of the Gila River Unit 2 purchase as part of the 2020 Rate Order.
Executive Orders
On May 1, 2020, the President of the United States of America signed an Executive Order, Securing the United States Bulk-Power System. The Department of Energy issued a request for information seeking to understand current industry practices surrounding supply chain components of the bulk-power system. In August 2020, we participated in the preparation of industry comments facilitated by the Edison Electric Institute. On January 20, 2021, the President signed an Executive Order suspending the prior Executive Order for 90 days, during which time the Secretary of Energy and the Director of the Office of Management and Budget have been directed to consider whether a replacement order should be issued. We are continuing to monitor the status and potential impacts of these Executive Orders.
Production Tax Credits
Federal renewable electricity PTCs are earned as energy from qualifying wind-powered facilities is generated based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law. Qualifying generating facilities are eligible for the credit for 10 years from the date the facilities are placed in service. The PTC rate is published annually by the IRS and was $0.025 per kWh generated for 2020. The Company will begin earning PTCs once Oso Grande begins generating power to serve our customers. If placed in service in the first half of 2021, Oso Grande is expected to generate approximately $20 million in PTCs in 2021. The PTCs are anticipated to offset most of the operating and interest expenses of Oso Grande, which are currently not in base rates.
Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions are unfavorable or below our estimates, the project’s electricity generation and associated PTCs may be substantially different than forecasted.
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 such period. By contrast, lower sales of power occur during the first quarter 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 risks and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of TEP's results of operations that do not have a significant impact on net income include:
•Cost Recovery Mechanisms - TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, Renewable Energy Standard Tariff, and DSM, 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 cost recovery 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 TEP's results of operations for the year ended 2020 compared to 2019 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) 2020 2019 Percent 2018 Percent
Operating Revenues
Retail $ 1,039 $ 972 6.9 % $ 1,022 (4.9) %
Wholesale, Long-Term 34 34 - % 32 6.3 %
Wholesale, Short-Term (1)
151 200 (24.5) % 197 1.5 %
Transmission 30 32 (6.3) % 29 10.3 %
Springerville Units 3 and 4 Participant Billings 78 108 (27.8) % 84 28.6 %
Other 93 72 29.2 % 69 4.3 %
Total Operating Revenues $ 1,425 $ 1,418 0.5 % $ 1,433 (1.0) %
(1)Revenues associated with derivatives are primarily returned to retail customers by offsetting the fuel and purchase power costs eligible for recovery through the PPFAC mechanism similar to short-term wholesale sales. As a result, revenues associated with derivatives are included in Wholesale, Short-Term in the table above.
TEP reported Operating Revenues of $1,425 million in 2020 compared with $1,418 million in 2019. The increase of $7 million, or less than 1%, was primarily due to:
•$34 million in higher retail revenue primarily due to higher fuel and purchase power recoveries due to higher rates and increased volumes;
•$24 million in higher retail revenue primarily due to favorable weather;
•$13 million in higher other revenue due to an increase in LFCR revenue;
•$8 million in higher retail revenue due to higher RES cost recoveries as a result of higher program expenses; and
•$7 million in higher retail revenue due to a natural gas transportation asset management agreement contract entered into in 2020.
The increase was partially offset by:
•$48 million in lower wholesale short-term sales primarily due to a decrease in volumes driven by the expiration of a capacity sale contract in December 2019; and
•$29 million in lower participant billings related to Springerville Units 3 and 4.
The following table provides key statistics impacting Operating Revenues:
Years Ended December 31, Increase (Decrease) Year Ended
December 31, Increase (Decrease)
(kWh in millions) 2020 2019 Percent 2018 Percent
Electric Sales (kWh) (1)
Retail Sales 9,111 8,744 4.2 % 8,900 (1.8) %
Wholesale, Long-Term 508 490 3.7 % 424 15.6 %
Wholesale, Short-Term 5,279 7,257 (27.3) % 6,279 15.6 %
Total Electric Sales 14,898 16,491 (9.7) % 15,603 5.7 %
Average Revenue per kWh (2)
Retail 11.40 11.12 2.5 % 11.48 (3.1) %
Wholesale, Long Term 6.76 6.94 (2.6) % 7.52 (7.7) %
Wholesale, Short-Term 2.84 2.87 (1.0) % 3.19 (10.0) %
Total Retail Customers (3)
433,421 428,626 1.1 % 425,044 0.8 %
(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
TEP reported Fuel and Purchased Power expense of $515 million in 2020 compared with $506 million in 2019. The increase of $9 million, or 2%, was primarily due to:
•$55 million in higher PPFAC recoveries primarily due to: (i) an increase in the PPFAC rate; and (ii) a decrease in PPFAC eligible costs; and
•$9 million in higher purchased power primarily due to an increase in: (i) price; and (ii) the retirement of RECs; partially offset by a decrease in volume due to the purchase of Gila River Unit 2.
The increase was partially offset by $56 million in lower fuel costs primarily due to decreases in: (i) Coal-Fired Generation volumes; (ii) losses on natural gas swap agreements; and (iii) natural gas prices.
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) 2020 2019 Percent 2018 Percent
Sources of Energy
Coal-Fired Generation 5,778 7,046 (18.0) % 7,208 (2.2) %
Gas-Fired Generation 7,582 7,714 (1.7) % 6,738 14.5 %
Utility-Owned Renewable Generation 84 75 12.0 % 82 (8.5) %
Total Generation 13,444 14,835 (9.4) % 14,028 5.8 %
Purchased Power, Non-Renewable 1,360 1,709 (20.4) % 1,624 5.2 %
Purchased Power, Renewable 681 643 5.9 % 652 (1.4) %
Total Generation and Purchased Power (1)
15,485 17,187 (9.9) % 16,304 5.4 %
(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal 2.51 2.46 2.0 % 2.44 0.8 %
Natural Gas (3)
2.03 2.33 (12.9) % 2.54 (8.3) %
Average Cost of Purchased Power (4)
Purchased Power, Non-Renewable 6.26 4.09 53.1 % 4.32 (5.3) %
Purchased Power, Renewable 9.42 9.43 (0.1) % 9.41 0.2 %
(1)This number represents the kWh generated from TEP's 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 Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation stations.
(3)Includes realized gains and losses from hedging activity.
(4)This metric represents the fuel 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
TEP reported Operations and Maintenance expense of $352 million in 2020 compared with $378 million in 2019. The decrease of $26 million, or 7%, in 2020 compared with 2019 was primarily due to lower reimbursable maintenance expense related to Springerville Unit 3 planned outages in 2019 not recurring in 2020.
Depreciation and Amortization Expense
Depreciation and Amortization expense increased by $21 million, or 11%, in 2020 compared with 2019 primarily due to an increase in asset base.
Other Income (Expense)
TEP reported other expense of $49 million in 2020 compared with $62 million in 2019. The decrease of $13 million, or 21%, in 2020 compared with 2019 was primarily due to:
•$12 million in lower finance lease interest expense related to PPFAC recoverable demand charges due to the purchase of Gila River Unit 2 in December 2019;
•$11 million in higher AFUDC primarily due to an increase in construction projects and a FERC Order that provided for an adjustment in the AFUDC calculation; and
•$6 million increase in other income due to an increase in expected return on pension plan assets.
The decrease was partially offset by:
•$11 million in higher interest expense primarily related to long-term debt issuance in 2020, partially offset by lower interest expense related to the Springerville Common Facilities finance leases; and
•$4 million decrease in value of investments used to support certain post-employment benefits as a result of less favorable market conditions.
Income Tax Expense
TEP reported income tax expense of $41 million in 2020 compared with $34 million in 2019. The increase of $7 million, or 21%, in 2020 compared with 2019 was primarily due to:
•$5 million in lower tax credits primarily related to investment tax credit amortization and AMT credits recognized in first quarter 2019 related to a revision in tax law guidance not recurring in 2020;
•$3 million in higher tax expense due to an increase in taxable earnings; and
•$3 million in higher EDIT amortization.
The increase was partially offset by $5 million related to higher AFUDC equity in 2020 primarily due to Oso Grande project costs included in construction work in progress.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
The COVID-19 pandemic has negatively impacted the global economy and created significant volatility and disruption of financial markets. An extended period of economic disruption could negatively affect our business and financial condition, and access to sources of liquidity. In addition, cash flows may 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 TEP's summer peaking load. We use our revolving credit agreement as needed to fund our business activities. We believe that we have sufficient liquidity under our revolving 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 depends on a variety of factors, including our credit ratings and conditions in the bank and capital markets.
Available Liquidity
(in millions) December 31, 2020
Cash and Cash Equivalents $ 61
Amount Available under Revolving Credit Agreement (1)
Total Liquidity $ 299
(1)The 2015 Credit Agreement provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million and a maturity date of October 2022.
Future Liquidity Requirements
We expect to meet all of our 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) contracted obligations including those forecasted in the Capital Expenditures table below.
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk for additional information regarding TEP's 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 TEP's 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) 2020 2019 Percent 2018 Percent
Operating Activities $ 466 $ 414 12.6 % $ 457 (9.4) %
Investing Activities (867) (654) 32.6 % (433) 51.0 %
Financing Activities 455 115 295.7 % 79 45.6 %
Net Increase (Decrease) 54 (125) * 103 *
Beginning of Period 28 153 (81.7) % 50 206.0 %
End of Period (1)
$ 82 $ 28 192.9 % $ 153 (81.7) %
* 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 $52 million in 2020 compared with 2019 primarily due to: (i) higher customer usage related to favorable weather; (ii) fuel and purchase power recoveries as a result of changes in the PPFAC rate; (iii) a settlement payment in 2019 for final mine reclamation settlement associated with the early retirement of Navajo, not recurring in 2020; (iv) AMT credit refunds received as a result of provisions of the CARES Act; and (iv) a decrease in amounts returned to customers through bill credits related to the TCJA.
The increase was partially offset by: (i) higher interest paid as a result of 2020 debt issuances; (ii) an increase in cash paid for pension funding; and (iii) changes in working capital related to higher sales and the timing of billing collections.
Investing Activities
Net cash flows used for investing activities increased by $213 million in 2020 compared with 2019 primarily due to higher capital expenditures resulting from: (i) $285 million in payments for the Oso Grande project under the BTA; and (ii) an $8 million payment for other investments.
The increase was offset by a decrease in cash used to purchase additional interests in generation facilities, net of proceeds received from the sale of an interest in a facility.
Financing Activities
Net cash flows provided by financing activities increased by $340 million in 2020 compared with 2019 primarily due to: (i) higher proceeds related to the issuance of senior unsecured notes in 2020, net of debt repayments; and (ii) an increase in equity contributions from 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, 2020, TEP had no short-term investments.
Access to Credit Agreements
We have access to working capital through our credit agreements.
Amounts borrowed from the 2019 Credit Agreement were used (i) to complete the purchase of Gila River Unit 2; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the 2019 Credit Agreement's outstanding term loan and the agreement was terminated.
Amounts borrowed from the 2015 Credit Agreement will be used for working capital and other general corporate purposes and LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of December 31, 2020, there was $238 million available under the 2015 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 credit agreements.
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 extends and expands the existing financing authority by: (i) extending authority from December 2020 to December 2025; (ii) increasing the outstanding long-term debt limitation from $2.2 billion to $2.9 billion; (iii) allowing parent equity contributions of up to $700 million; and (iv) providing for credit facilities of up to $300 million in the aggregate.
In April 2020, we issued and sold $350 million aggregate principal amount of 4.00% senior unsecured notes due June 2050 to repay: (i) $225 million of outstanding borrowings under our 2019 Credit Agreement, which we terminated; and (ii) outstanding borrowings under our 2015 Credit Agreement and for general corporate purposes.
In August 2020, we issued and sold $300 million aggregate principal amount of 1.50% senior unsecured notes due August 2030. An amount equal to the net proceeds was allocated to the total costs of Oso Grande.
In September 2020, we extinguished our obligations for two series of fixed rate tax-exempt bonds with principal amounts of $80 million and $100 million.
TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, we may refinance other debt issuances or repurchase debt in the future.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2020, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- and A3, respectively.
Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.
Certain of TEP's debt agreements contain pricing based on our credit ratings. A change in TEP’s 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 TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of December 31, 2020, TEP was in compliance with these covenants.
We do not have any provisions in any of our debt or lease 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
UNS Energy made equity contributions to TEP of $250 million in 2020 and $50 million in 2019. The proceeds provided additional liquidity to TEP and were used for investments in generation, transmission, and distribution assets.
Dividends Declared and Paid to Parent
TEP declared and paid $75 million in dividends to UNS Energy in 2020 and 2019.
Master Trading Agreements
TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits provided to TEP based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of December 31, 2020, TEP had posted $7 million of cash posted as collateral to provide credit enhancement with its counterparties related to our wholesale marketing or risk management activities.
Capital Expenditures
TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. TEP is prioritizing capital projects to mitigate supply chain risk and other potential impacts of the COVID-19 pandemic and ensure we continue providing safe and reliable service while supporting public health. As a result, forecasted capital expenditures for 2020 were reduced due to prioritizing certain projects and postponing others. In 2020, total capital expenditures of $840 million included: (i) the purchase of Springerville Common Facilities in December 2020; (ii) $331 million in payments for Oso Grande under the BTA; and (iii) other investments in generation, transmission, and distribution assets. In 2019, total capital expenditures of $608 million included: (i) the purchase of Gila River Unit 2 in December 2019; (ii) $47 million in payments for Oso Grande under the BTA; and (iii) other investments in generation assets and an enhanced metering and distribution network.
Our forecasted capital expenditures presented below exclude amounts for AFUDC and other non-cash items:
Year Ended December 31,
(in millions) 2021 2022 2023 2024 2025
Generation Facilities:
Renewable Energy (1)
$ 30 $ 4 $ 97 $ 226 $ 5
Other Generation Facilities 57 49 51 37 43
Total Generation Facilities 87 53 148 263 48
Transmission and Distribution (2)
301 371 353 268 208
General and Other (3)
118 57 55 49 67
Total Capital Expenditures $ 506 $ 481 $ 556 $ 580 $ 323
(1)Includes investments in renewable energy that will allow us to continue to move toward our long-term strategy of shifting to a more diverse, sustainable energy portfolio. On February 2, 2021, TEP made a payment of $10 million for Oso Grande under the BTA.
(2)Increases due to investments in transmission capacity and system reinforcements.
(3)Includes cost 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, construction schedules, 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.
Oso Grande Wind Project
In 2019, we entered into a BTA to develop Oso Grande, which is expected to be placed in service in the first half of 2021. The Oso Grande project will add approximately 250 MW of wind-powered electric generation, increasing our total renewable nominal generation capacity to over 500 MW, which includes PPAs and owned utility-scale generation. The project is estimated to cost $436 million, which includes, among other costs, $27 million for AFUDC and $397 million related to the BTA. As of December 31, 2020, total cost of construction incurred from inception was $413 million, which included, among other costs, $22 million for AFUDC and $378 million related to the BTA. The project costs incurred are currently included in Construction Work in Progress on the Consolidated Balance Sheets.
See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the BTA.
Income Tax Position
TEP did not make any U.S. federal or Arizona state income tax payments during 2020 due to existing net operating loss and tax credit carryforwards in those jurisdictions. Based on our remaining carryforward balances and limitations on their use in individual years, we expect to make U.S. federal and state income tax payments in 2021. The payments are not expected to have a significant impact on our operating cash flows.
Payroll Tax
In response to the COVID-19 pandemic, the CARES Act was signed into law on March 27, 2020. As permitted by the CARES Act, TEP deferred payment of the employer's portion of social security taxes. In 2020, TEP recorded total deferred deposits of $7 million in Accrued Taxes Other than Income Taxes and Regulatory and Other Liabilities-Other on the Consolidated Balance Sheets. TEP expects the total deferred deposits to be paid to the IRS in equal payments in 2021 and 2022.
Environmental Matters
The EPA regulates 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. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.
We capitalized $4 million in 2020 and 2019 in costs incurred to comply with environmental rules and regulations. In addition, we recorded operations and maintenance expenses related to environmental compliance of $5 million in 2020 and 2019, and $6 million in 2018. We expect environmental compliance related capital expenditures of $1 million in 2021 through 2023, $2 million in 2024, and less than $1 million in 2025. TEP will request recovery from its 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. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a State Implementation Plan (SIP), and must review and submit revisions to the SIP on a periodic basis.
In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The ADEQ began to develop a control strategy with a focus on making reasonable progress toward the national visibility goal. In July 2019, the ADEQ notified TEP that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluation.
TEP conducted the potential emissions controls evaluations, commonly referred to as the four factor analysis, for both facilities. These evaluations were submitted to the ADEQ in March 2020 for the agency's use in developing the revised SIP. TEP will continue to work with the agency to determine compliance strategies as needed. The ADEQ must submit the revised SIP to the EPA for approval by July 2021. Based on current Regional Haze requirement time-frames, TEP anticipates that compliance strategies, if any, will likely be required to be implemented three to five years after the 2021 SIP submittal date. TEP cannot predict the outcome of these matters at this time.
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. The plan targeted CO2 emissions reductions for existing facilities by 2030 and established interim goals that begin in 2022.
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 Greenhouse Gas (GHG) emissions. The BSER for GHG emissions from existing coal-fired generation facilities is defined as Heat-Rate Improvements (HRI) 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.
On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the ACE Rule to the EPA. The decision also vacated amendments that extended the timeline under which companies had to come into compliance with the rule. Vacating the ACE rule and the amendments is not effective until the D.C. Circuit issues its written order of the decision, or mandate. The D.C. Circuit has discretion to withhold its mandate and, thus, preserve the status quo, pending any appeals of its decision. As of February 11, 2021, the written order has not yet been issued.
TEP cannot predict the ultimate outcome of these matters at this time, but will continue to monitor legal challenges, legislative efforts, and administrative rulemakings.
Coal Combustion Residuals Regulation
In April 2015, the EPA issued a final rule requiring disposal of coal ash and other CCR to be managed as a solid waste under Subtitle D of the RCRA for disposal in landfills and/or surface impoundments. Our share of costs to comply with the CCR rule at Four Corners is estimated to be $3 million. This includes estimated costs for corrective action for two CCR units at the facility, which will be incurred over 30 years. APS, the operating agent of Four Corners, began an assessment of corrective measures in 2019 and expects the assessment to continue into 2021.
Since these regulations were finalized, the EPA has taken steps to substantially modify these rules. The following are pending rulemakings that could have a material impact on TEP:
•In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act, which gave the EPA authority to either authorize states to establish their own permit program under RCRA for implementing regulation of CCR or issue federal permits in states without a program and on tribal lands. In accordance with this Act,
the EPA proposed to establish a federal CCR permit program on February 20, 2020. Public comment on the EPA's proposal closed in August 2020.
•On March 15, 2018, the EPA proposed to add boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. In a separate proposal dated August 14, 2019, the EPA acknowledged that if it finalizes the addition of boron it will need to establish an alternative risk-based groundwater protection standard for boron, as boron does not have a Maximum Contaminant Level.
As of December 31, 2020, the EPA has not taken final action on these proposals. As a result, TEP cannot predict the impact on operations or financial results from the proposed rulemakings.
Effluent Limitation Guidelines
In 2015, as part of the Clean Water Act, the EPA published the final Steam Electric Power Generating category Effluent Limitation Guidelines and Standard rule, revising standards and limitations for coal-fired generation wastewater discharges. The rule established new or additional Effluent Limitations Guidelines (ELG) for wastewater discharges associated with fly ash, bottom ash, flue gas desulfurization, flue gas mercury control, and gasification of fuels such as coal and petroleum coke. In response to legal challenges, the EPA revised the ELGs and issued a final rule on August 31, 2020. The final rule revised requirements for flue gas desulfurization wastewater and bottom ash transport water.
With the exception of Four Corners, none of TEP's coal-fired generation facilities are subject to the final rule. With regard to Four Corners, the revised ELGs warrant a modification of the facility's wastewater discharge permit, or National Pollution Discharge Elimination System permit, which was last issued in September 2019. We do not know the timing of when APS, the operator of Four Corners, will submit the expected permit modification to the EPA. TEP does not anticipate a material impact on operations or financial results.
CRITICAL ACCOUNTING POLICIES AND 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 included as an expense, or in AOCI, in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally 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. 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, 2020, regulatory liabilities net of regulatory assets in the balance sheet totaled $99 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 would reflect our pension and other postretirement plan regulatory assets or liabilities in AOCI and recognize the impact of other regulatory assets and liabilities on 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.
Revenue Recognition
TEP’s retail revenues, which are recognized in the period that electricity is delivered and consumed by customers, include unbilled revenue based on an estimate of kWh delivered at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment, including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated kWh delivered to the kWh billed to our retail customers. The excess
of estimated kWh delivered over kWh billed is allocated to the retail customer classes based on estimated usage by each customer class. We then record revenue for each customer class based on the Retail Rates for each customer class. Due to the seasonal fluctuations of TEP’s actual load, unbilled revenues increase during the spring and summer and decrease during the fall and winter. A provision for uncollectible accounts associated with retail revenues is recorded as a component of operations and maintenance expense.
Income Taxes
Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate as of our balance sheet date. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS.
A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. TEP recorded no valuation allowance as of December 31, 2020. See Note 14 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding income taxes.
Plant Asset Depreciable Lives
TEP has 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 expected net removal costs. The ACC approves depreciation rates for all generation and distribution assets. Depreciation rates for such assets cannot be changed without the ACC's approval. TEP's 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. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset and subsequently amortized over the life of the underlying asset. Accretion of the liability and amortization of the associated asset are deferred as regulatory assets because these costs are expected to be recovered through depreciation rates.
TEP identified legal obligations to retire generation facilities specified in land leases for its jointly-owned Four Corners and Navajo facilities. These stations 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. TEP is currently removing facilities at Navajo at the request of the Navajo Nation. TEP also has certain environmental obligations at Gila River, Luna, San Juan, Sundt and Springerville. TEP estimates that its 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 $205 million at the retirement dates. Additionally, TEP entered into land lease agreements or land easement agreements with certain landowners for the installation of PV assets. The provisions of the PV land leases or land easements require TEP to remove the PV facilities upon expiration of the agreements. In addition, TEP is required to properly dispose or recycle the PV assets under RCRA. We estimated our ARO related to the PV assets to be approximately $19 million at the retirement dates. We have identified no other legal obligations to retire generation plant assets.
TEP has various transmission and distribution lines that operate under land easements and rights-of-way that contain end dates and may contain site restoration clauses. TEP operates 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 $96 million as of December 31, 2020. 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 for TEP 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, less actual removal costs incurred, net of 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
TEP records the underfunded amount for its pension and other postretirement obligations as a liability. 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 through rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability 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, 2020, TEP discounted its future pension plan obligations at 2.9% and its other postretirement plan obligations at a rate of 2.6%. The discount rate for future pension plan and other postretirement 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, TEP reviews the asset allocation and develops 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, 2020, TEP assumed that its pension plans’ assets would generate a long-term rate of return of 6.75%.
Compensation Increases
As of December 31, 2020, TEP used a rate of compensation increase of 2.8% to measure pension obligations.
Mortality
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, 2020, compared to a modified version of improvement scale MP-2019 used to measure pension obligations as of December 31, 2019.
Healthcare Cost Trend Rates
TEP used a current year healthcare cost trend rate range between 6.1% and 7.1% in valuing its other postretirement benefit obligation as of December 31, 2020. This rate reflects both market conditions and historical experience.
Sensitivity Analysis
The table below shows the effect on TEP's expense and obligation of a 100 basis point change to its assumptions as of December 31, 2020:
Effect on Expense Effect on Obligation
(in millions) Increase Decrease Increase Decrease
Change to Pension
Discount Rate $ (7) $ 9 $ (85) $ 107
Long-Term Rate of Return on Plan Assets (4) 4 N/A N/A
Change to Other Postretirement Benefits
Discount Rate (1) 1 (10) 13
Long-Term Rate of Return on Plan Assets - - N/A N/A
Healthcare Cost Trend Rate 1 (1) 10 (8)
In 2021, TEP will incur pension costs of $9 million and other postretirement benefit costs of $7 million. TEP expects to record: (i) $21 million to operations and maintenance expense; (ii) $6 million to capital; and (iii) $11 million to other income. In 2021, TEP expects to make: (i) pension plan contributions of $13 million; (ii) benefit payments to retirees under the retiree benefit plan of $6 million; and (iii) contributions to the VEBA trust of $1 million, net of distributions.
See Note 10 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension plan and other postretirement benefit plan expenses and obligations.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
TEP enters 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, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it will have excess supply, and the market price of energy exceeds its marginal cost. TEP enters into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted natural gas purchases and to hedge the price risk associated with forward PPAs that are indexed to natural gas prices.
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 TEP’s derivative instruments as of December 31, 2020, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
TEP manages 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 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’s financial statements are 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 interest rates, commodity and coal prices, 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 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.
Interest Rate Risk
Credit Agreements
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under its credit agreements. The interest rate paid on borrowings is variable. Amounts borrowed under the credit agreements are made on either the basis of a spread over LIBOR or an ABR. As a result, TEP may experience significant volatility in the rates paid on LIBOR borrowings under its credit agreements.
The 2015 Credit Agreement is scheduled to mature in October 2022 and provides for up to $250 million in revolving credit commitments and a sub-limit of $50 million in LOC facilities. As of December 31, 2020, TEP had $12 million in LOCs outstanding and no borrowings under the revolving credit commitments.
Commodity and Coal 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. Our load and generation facilities represent substantial underlying commodity positions. Exposure to commodity prices consist primarily of variations in the price of fuel required to generate electricity that is purchased and sold in retail and wholesale markets. Commodity and coal 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 our RMC, we mitigate a portion of its commodity price risk through the use of commodity contracts, which include forwards, financial swaps, and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. Our exposure to commodity and coal price risk is limited by our ability to include these costs in regulated rates through our PPFAC mechanism, which is subject to review annually 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 our derivative positions:
(in millions) 2020 2019 2018
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ 21 $ (45) $ (9)
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, 2020
Prices Actively Quoted $ 5 $ (17) $ (37) $ (49)
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. We primarily record unrealized gains and losses as either a regulatory asset or liability. As contracts settle, the 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 $9 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 $22 million.
Coal Supply Agreements
We are subject to fuel price risk from changes in the price of coal used to fuel our coal-fired generation facilities. This risk is mitigated through the use of long-term coal supply agreements with limited price movement. Our coal supply agreements expire from 2022 through 2031. While we do expect coal reserves from the supplying mines to be sufficient to fulfill the estimated requirements for each coal-fired generation facility's estimated remaining life, we are seeking alternative coal sources to ensure we have sufficient supply in the event of early closure of our current supplying mines. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Credit Risk
We are exposed to credit risk in our energy-related marketing activities related to potential non-performance by counterparties. We manage the risk of counterparty default 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 mark-to-market value of any forward contracts. If exposure exceeds credit limits or contractual collateral thresholds, we may request that a counterparty provide credit enhancement in the form of cash collateral or an LOC. In response to the COVID-19 pandemic, we have increased our monitoring of the effects of the economic slowdown on counterparties’ abilities to perform under their contractual obligations.
We have entered into short-term and long-term transactions related to our wholesale marketing and gas hedging activities with various counterparties. As of December 31, 2020, our total credit exposure was approximately $17 million, and we had approximately $1 million of exposure to non-investment grade counterparties.
As of December 31, 2020, we had $7 million of cash posted as collateral to provide credit enhancement to a counterparty. As of December 31, 2020, we held approximately $4 million in collateral from our wholesale counterparties.

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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, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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 applies the specialized rules to account for the effects of cost-based rate regulation under accounting principles generally accepted in the United States of America. 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 property, plant, and equipment;
regulatory assets and liabilities; operating revenues; fuel expense, purchased power expense; operations 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 affected account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of: (1) recovery of costs incurred in future rates, (2) potential refunds to customers, (3) a disallowance of part of the cost of recently completed plant or plant under construction, and (4) probability of potential charges related to the abandonment of regulated plants. While the Company has indicated they expect to recover costs from customers through regulated rates, there is a risk that the respective regulatory authority will not approve full recovery of the costs incurred. Auditing these matters required especially subjective judgement and specialized knowledge of accounting for rate regulation due to their 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 controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or a future reduction in rates.
•We read relevant regulatory rate orders and settlements issued by the respective regulatory authorities for the Company and other public utilities in Arizona, regulatory statutes and interpretations as well as procedural memorandums, utility and intervenor filings, and other publicly available information to evaluate the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances.
•For relevant regulatory matters in process, we inspected the Company’s filings with the respective regulatory authorities and the filings with the ACC by intervenors that may impact the Company’s future rates, for evidence that might contradict management’s assertions.
•We inquired of management about property, plant, and equipment 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 meetings of the board of directors, regulatory orders and other regulatory filings for any evidence that may contradict management’s assertion regarding recoverability of such costs.
•We compared actual spend for projects that have been capitalized to property, plant, and equipment to budget. We evaluated regulatory filings for any indication that the recoverability of costs of significant capital projects were challenged by regulators, intervenors or others. For significant projects that were over budget or if full recovery of project costs was being challenged, we evaluated management’s assessment of the probability of a potential disallowance of costs.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 11, 2021
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,
2020 2019 2018
Operating Revenues $ 1,424,741 $ 1,418,338 $ 1,432,618
Operating Expenses
Fuel 302,637 358,394 351,749
Purchased Power 146,968 137,977 134,914
Transmission and Other PPFAC Recoverable Costs 52,860 52,261 46,595
Increase (Decrease) to Reflect PPFAC Recovery Treatment 12,565 (42,836) 9,885
Total Fuel and Purchased Power 515,030 505,796 543,143
Operations and Maintenance 351,584 377,563 361,963
Depreciation 189,051 169,042 158,310
Amortization 28,754 27,706 26,052
Taxes Other Than Income Taxes 58,222 55,642 55,006
Total Operating Expenses 1,142,641 1,135,749 1,144,474
Operating Income 282,100 282,589 288,144
Other Income (Expense)
Interest Expense (88,214) (88,511) (67,620)
Allowance For Borrowed Funds 9,480 5,744 3,151
Allowance For Equity Funds 22,847 15,222 8,117
Unrealized Gains (Losses) on Investments 1,741 6,015 (2,301)
Other, Net 4,903 (491) 1,814
Total Other Income (Expense) (49,243) (62,021) (56,839)
Income Before Income Tax Expense 232,857 220,568 231,305
Income Tax Expense 41,452 34,053 42,982
Net Income $ 191,405 $ 186,515 $ 188,323
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in thousands)
Years Ended December 31,
2020 2019 2018
Comprehensive Income
Net Income $ 191,405 $ 186,515 $ 188,323
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax (Expense) Benefit of $0, $(44), and $(121)
- 133 364
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax (Expense) Benefit of $1,052, $1,059, and $(747)
(3,171) (3,190) 2,026
Total Other Comprehensive Income (Loss), Net of Tax (3,171) (3,057) 2,390
Total Comprehensive Income $ 188,234 $ 183,458 $ 190,713
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,
2020 2019 2018
Cash Flows from Operating Activities
Net Income $ 191,405 $ 186,515 $ 188,323
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense 189,051 169,042 158,310
Amortization Expense 28,754 27,706 26,052
Amortization of Debt Issuance Costs 2,721 2,326 2,339
Use of Renewable Energy Credits for Compliance 44,517 37,141 32,350
Deferred Income Taxes 39,408 41,614 56,066
Pension and Other Postretirement Benefits Expense 14,883 17,762 15,303
Pension and Other Postretirement Benefits Funding (21,018) (16,749) (26,673)
Allowance for Equity Funds Used During Construction (22,847) (15,222) (8,117)
Regulatory Deferral, ACC Refund Order (7,705) 7,705 (1,562)
Changes in Current Assets and Current Liabilities:
Accounts Receivable (19,019) 9,238 (26,729)
Materials, Supplies, and Fuel Inventory (3,460) (16,236) (2,357)
Regulatory Assets 5,339 (20,934) (4,080)
Other Current Assets (8,311) (475) (1,746)
Accounts Payable and Accrued Charges (20,885) (27,776) 33,536
Income Taxes Receivable 10,245 6,072 (13,004)
Regulatory Liabilities 41,287 (1,626) 14,028
Other, Net 1,689 8,140 15,187
Net Cash Flows-Operating Activities 466,054 414,243 457,226
Cash Flows from Investing Activities
Capital Expenditures (839,958) (607,593) (392,522)
Proceeds from Sale, Springerville Common Facilities 29,569 - -
Purchase Intangibles, Renewable Energy Credits (53,509) (51,699) (51,327)
Purchase, Other Investments (8,500) - -
Contributions in Aid of Construction 4,615 6,607 10,817
Note Receivable - (1,000) -
Net Cash Flows-Investing Activities (867,783) (653,685) (433,032)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility 105,000 - 171,000
Repayments of Borrowings, Revolving Credit Facility (105,000) - (206,000)
Proceeds from Borrowings, Term Loan 60,000 165,000 -
Repayments of Borrowings, Term Loan (225,000) - -
Proceeds from Issuance, Long-Term Debt-Net of Discount
645,768 - 298,869
Repayments of Long-Term Debt (180,410) (14,700) (136,700)
Dividends Paid to Parent (75,000) (75,000) (85,000)
Payments of Finance Lease Obligations (17,087) (10,890) (10,930)
Payment of Debt Issuance Costs (6,327) (757) (3,265)
Contributions from Parent 250,000 50,000 50,000
Other 3,316 1,514 1,078
Net Cash Flows-Financing Activities 455,260 115,167 79,052
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash 53,531 (124,275) 103,246
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 28,472 152,747 49,501
Cash, Cash Equivalents, and Restricted Cash, End of Period $ 82,003 $ 28,472 $ 152,747
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,
2020 2019
ASSETS
Utility Plant
Plant in Service $ 7,073,292 $ 6,663,912
Utility Plant Under Finance Leases - 151,467
Construction Work in Progress 627,382 303,488
Total Utility Plant 7,700,674 7,118,867
Accumulated Depreciation and Amortization (2,645,333) (2,506,686)
Accumulated Amortization of Finance Lease Assets - (77,285)
Total Utility Plant, Net 5,055,341 4,534,896
Investments and Other Property 76,299 62,136
Current Assets
Cash and Cash Equivalents 60,960 9,762
Accounts Receivable (Net of Allowance for Credit Losses of $13,260 and $5,716)
173,412 154,847
Fuel Inventory 21,946 23,731
Materials and Supplies 126,788 121,542
Regulatory Assets 123,588 138,412
Derivative Instruments 16,094 3,596
Other 23,895 21,416
Total Current Assets 546,683 473,306
Regulatory and Other Assets
Regulatory Assets 318,474 326,860
Derivative Instruments 725 2,763
Other 92,605 89,196
Total Regulatory and Other Assets 411,804 418,819
Total Assets $ 6,090,127 $ 5,489,157
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,
2020 2019
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, 2020 and 2019)
$ 1,646,539 $ 1,396,539
Capital Stock Expense (6,357) (6,357)
Retained Earnings 712,197 595,792
Accumulated Other Comprehensive Loss (10,942) (7,771)
Total Common Stock Equity 2,341,437 1,978,203
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2020 and 2019)
- -
Finance Lease Obligations - 67,316
Long-Term Debt, Net 1,814,059 1,522,087
Total Capitalization 4,155,496 3,567,606
Current Liabilities
Current Maturities of Long-Term Debt, Net 249,752 80,330
Borrowings Under Credit Agreements - 165,000
Finance Lease Obligations - 17,086
Accounts Payable 109,461 136,465
Accrued Taxes Other than Income Taxes 50,278 42,741
Accrued Employee Expenses 35,129 32,567
Accrued Interest 16,337 16,700
Regulatory Liabilities 151,189 96,017
Customer Deposits 16,450 24,568
Derivative Instruments 27,789 27,615
Other 22,031 23,678
Total Current Liabilities 678,416 662,767
Regulatory and Other Liabilities
Deferred Income Taxes, Net 492,919 432,484
Regulatory Liabilities 390,164 477,495
Pension and Other Postretirement Benefits 163,652 133,452
Derivative Instruments 37,958 48,697
Other 171,522 166,656
Total Regulatory and Other Liabilities 1,256,215 1,258,784
Commitments and Contingencies
Total Capitalization and Other Liabilities $ 6,090,127 $ 5,489,157
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, 2017 $ 1,296,539 $ (6,357) $ 380,076 $ (6,226) $ 1,664,032
Net Income 188,323 188,323
Other Comprehensive Income, Net of Tax 2,390 2,390
Dividends Declared to Parent (85,000) (85,000)
Contribution from Parent 50,000 50,000
Adoption of ASU, Cumulative Effect Adjustment 878 (878) -
Balances as of December 31, 2018 $ 1,346,539 $ (6,357) $ 484,277 $ (4,714) $ 1,819,745
Net Income 186,515 186,515
Other Comprehensive Loss, Net of Tax (3,057) (3,057)
Dividends Declared to Parent (75,000) (75,000)
Contribution from Parent 50,000 50,000
Balances as of December 31, 2019 $ 1,396,539 $ (6,357) $ 595,792 $ (7,771) $ 1,978,203
Net Income 191,405 191,405
Other Comprehensive Loss, Net of Tax (3,171) (3,171)
Dividends Declared to Parent (75,000) (75,000)
Contributions from Parent 250,000 250,000
Balances as of December 31, 2020 $ 1,646,539 $ (6,357) $ 712,197 $ (10,942) $ 2,341,437
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 433,000 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 and transmission facilities 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. Most notably, TEP bifurcated Other, Net on the Consolidated Statements of Income as follows:
As Filed Amount Reclassified As Reclassified As Filed Amount Reclassified As Reclassified
(in thousands) Year Ended December 31, 2019 Year Ended December 2018
Other Income (Expense)
Other, Net $ 5,524 $ (6,015) $ (491) $ (487) $ 2,301 $ 1,814
Unrealized Gains (Losses) on Investments - 6,015 6,015 - (2,301) (2,301)
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 or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally 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
TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (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 a primary beneficiary of the VIEs on a quarterly basis.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2020, 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 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 FASB has been adopted as of January 1, 2020. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
Credit Losses
TEP adopted accounting guidance that requires entities to incorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. See Note 5 for additional disclosure about TEP's allowance for credit losses.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
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 generation 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 primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset or liability account based on the ACC's approval of these costs in its depreciation rates.
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 suits 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 on the balance sheet and reconciles their sum to the cash flow statement:
Years Ended December 31,
(in millions) 2020 2019 2018
Cash and Cash Equivalents $ 61 $ 10 $ 138
Restricted Cash included in:
Investments and Other Property 19 16 14
Current Assets-Other 2 2 1
Total Cash, Cash Equivalents, and Restricted Cash $ 82 $ 28 $ 153
Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets-Other represents the current portion of TEP's share of San Juan's mine reclamation costs.
ALLOWANCE FOR CREDIT LOSSES
TEP records an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical credit loss patterns, sales, current conditions, and reasonable and supportable forecasts. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible. See Note 5 for information regarding collection activity and adjustments to the allowance for credit losses related to the COVID-19 pandemic.
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, transmission, and distribution facilities. 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 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 plus removal costs less any salvage value. There is no impact to the income statement.
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 Retail Rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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:
2020 2019 2018
Average AFUDC Rates 6.63 % 7.86 % 7.12 %
Depreciation
Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets and include estimates for salvage value and removal costs. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC.
Below are the summarized average annual depreciation rates for all utility plant:
2020 2019 2018
Average Annual Depreciation Rates 3.15 % 3.08 % 3.13 %
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 the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense on 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 printing 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 remaining life of the original debt.
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.
OPERATING REVENUES
TEP earns the majority 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 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 the due date delinquent and charges the customer a late payment fee with the exception of service disconnection moratoriums. Generally, customers are not charged a late payment fee when service disconnection moratoriums are in effect. 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 the Company expects to be entitled and recognizes a refund liability until TEP is certain that the Company 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. See Note 4 for the disaggregation of TEP's Operating Revenues.
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. See Note 2 for additional information regarding regulatory matters.
RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS
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 requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file annual RES implementation plans for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through a RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the LFCR mechanism.
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 to implement DSM programs. The EE Standards required increasing annual targeted retail kWh savings equal to 22% by 2020. As of February 11, 2021, the ACC has not set annual target retail kWh savings requirements for future years. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism.
Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Operating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures.
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 surcharge. As described above, the market cost of conventional power or contract price for power is recoverable through the PPFAC mechanism.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. See Note 2 for additional information regarding regulatory matters. The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets-Other on the Consolidated Balance Sheets:
December 31,
(in millions) 2020 2019
Beginning of Period $ 63 $ 55
Purchased 48 45
Used for Compliance (45) (37)
End of Period $ 66 $ 63
TEP expenses the cost of internally developed RECs, including PBI activity that is not included in the table above and recoverable through the RES surcharge.
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.
Payroll Tax
In response to the COVID-19 pandemic, the CARES Act was signed into law on March 27, 2020. As permitted by the CARES Act, TEP deferred payment of the employer's portion of social security taxes. In 2020, TEP recorded total deferred deposits of $7 million in Accrued Taxes Other than Income Taxes and Regulatory and Other Liabilities-Other on the Consolidated Balance Sheets. TEP expects the total deferred deposits to be paid to the IRS in equal payments in 2021 and 2022.
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 on 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.
TEP accounts for federal energy credits generated prior to 2013 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. TEP had an aggregate liability balance of $6 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2020 and 2019. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2020 and 2019. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises.
TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees.
Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 10 for additional information regarding the employee benefit plans.
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. See Note 13 for additional information regarding fair value.
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. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities on the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.
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 on 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. See Note 13 for additional information regarding derivative instruments.
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 and transmission facilities, 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 and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RATE CASE MATTERS
2020 Rate Order
In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.
Provisions of the 2020 Rate Order include, but are not limited to:
•a non-fuel retail revenue increase of $58 million over test year retail revenues;
•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%;
•a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;
•approval to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;
•a TEAM that will be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and
•a TCA mechanism, updated annually, allowing TEP to recover changes in transmission costs approved by the FERC.
In addition, the 2020 Rate Order established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In January 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. TEP cannot predict the timing or outcome of these proceedings.
2019 FERC Rate Case
In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings.
Provisions of the order include, but are not limited to:
•replacing TEP's stated transmission rates with a forward-looking formula rate;
•a 10.4% return on equity; and
•elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor.
The requested forward-looking formula rate is intended to allow for a more timely recovery of transmission-related costs. As part of the order, the FERC established hearing and settlement procedures. On February 8, 2021, the Settlement Judge determined that the parties in the rate case proceeding were at an impasse and recommended ending the settlement process and appointing a Presiding Judge to continue the formula rate case proceeding. All rates charged under the revised OATT pursuant to the FERC order are subject to refund until the proceeding concludes. TEP reserved $15 million as of December 31, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities-Regulatory Liabilities on the Consolidated Balance Sheets. TEP cannot predict the outcome of the proceedings.
OTHER FERC MATTERS
On January 29, 2021, the FERC notified TEP that it is commencing an audit that is intended 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 will cover the period of January 1, 2018 to the present. TEP cannot predict the outcome or findings, if any, of the FERC audit at this time.
FEDERAL TAX LEGISLATION
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective in the second quarter of 2018 (ACC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Refund Order). The ACC Refund Order was based on the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that would be trued-up annually for actual results. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts were deferred to a regulatory liability or asset and were used to adjust the following year's bill credit amounts.
The table below summarizes the regulatory asset (liability) over or under collected balance related to the ACC Refund Order:
Years Ended December 31,
(in millions) 2020 2019
Beginning of Period $ - $ 4
ACC Approved Refund (Reduction in Operating Revenues) (38) (34)
Amount Returned to Customers Through Bill Credits 17 22
Regulatory Deferral (1)
20 8
TCJA Reclassification (1)
1 -
End of Period $ - $ -
(1)In December 2020, TEP reclassified the remaining over collected balance in the current regulatory account and in the long term regulatory deferral to the TEAM regulatory liability to be returned to customers in 2021.
TEP filed an informational filing with the ACC to establish a 2020 customer refund of $35 million. The refund was returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit accounted for 50% of the returned savings in 2020. There was no regulatory liability balance related to the deferred TCJA customer refunds as of December 31, 2020. TEP had recorded a regulatory liability balance related to the deferred TCJA customer refunds of $8 million as of December 31, 2019, in Regulatory and Other Liabilities-Regulatory Liabilities on the Consolidated Balance Sheets.
In December 2020, the ACC approved the TEAM as part of the 2020 Rate Order. The TEAM will return the refunds that TEP deferred to a regulatory liability through the initial TEAM rate through the end of 2021. TEP had recorded a regulatory liability balance related to the TEAM of $29 million as of December 31, 2020, in Current Liabilities-Regulatory Liabilities on the Consolidated Balance Sheets.
See Note 14 for additional information regarding the TCJA.
Federal Energy Regulatory Commission
In 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the order and the FERC approved TEP's proposal of an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, to be effective March 21, 2018. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
Also in 2018, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization on rates. In November 2019, the FERC issued a final rule on the NOPR which required TEP to address the effect of the TCJA and related EDIT amortization in its next FERC rate case. As required by the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.
See Note 14 for additional information regarding the TCJA.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms 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 reconciles the difference between actual costs and those recovered in the preceding 12-month period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below summarizes the PPFAC regulatory asset (liability) balance:
Years Ended December 31,
(in millions) 2020 2019
Beginning of Period $ 36 $ (17)
Deferred Fuel and Purchased Power Costs (1)
283 315
PPFAC and Base Power Recoveries (2)
(296) (262)
End of Period $ 23 $ 36
(1)Includes costs eligible for recovery through the PPFAC and base power rates.
(2)In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request, which went into effect on April 1, 2019. In March 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2020.
Environmental Compliance Adjustor
The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided that they are not already recovered in base rates or recovered through another commission-approved mechanism.
The eligible costs for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. Beginning January 2021, the difference between costs recovered through rates and actual ECA eligible costs is deferred to a balancing account as approved as part of the 2020 Rate Order. The Company 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. The Company recognized $4 million in 2020, $2 million in 2019, and $3 million in 2018 related to ECA revenues included in Operating Revenues on the Consolidated Statements of Income.
Tax Expense Adjustor Mechanism
The TEAM allows for the recovery of future significant income tax changes on a timely basis without waiting for the next rate case. The TEAM provides the Company the ability to pass through: (i) the TCJA Regulatory Deferral balance to the initial 2021 TEAM rate; (ii) the change in EDIT compared to the test year; and (iii) the income tax effects of tax legislation that materially impacts TEP's 2018 test year revenue requirements. The TEAM went into effect January 1, 2021, as approved in the 2020 Rate Order.
Transmission Cost Adjustor
The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA will be limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company will file a notice with the ACC no later than December 1st of each year with the ACC presenting a revised tariff that reflects the change in the formula OATT rate which will go into effect the first billing cycle in January. The TCA went into effect January 1, 2021, as approved in the 2020 Rate Order.
Renewable Energy Standard
The ACC’s RES requires Arizona regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2020 was 10% of retail electric sales, which will increase annually until renewable retail sales represent at least 15% by 2025. The RES also requires that DG account for 30% of the renewable energy requirement. Arizona utilities are required to file annual RES implementation plans for review and approval by the ACC.
In 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million. The recovery funds: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. The Company recognized less than $1 million in 2020 and 2019 and $1 million in 2018 of revenue as a return on company-owned solar projects. The return on company-owned solar projects is included in Operating Revenues on the Consolidated Statements of Income.
In 2020, the percentage of TEP's retail kWh sales attributable to the RES was approximately 16%, exceeding the overall 2020 RES requirement of 10%.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy Efficiency Standards
Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of December 31, 2020, TEP's cumulative annual energy savings was approximately 22%.
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 to implement DSM programs, as well as an annual performance incentive. The annual DSM performance incentive for the prior calendar year is recorded in the first quarter of each year. TEP recorded $2 million in 2020, 2019, and 2018 related to performance in Operating Revenues on the Consolidated Statements of Income.
In 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standard. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans. In June 2020, TEP filed its 2021 energy efficiency implementation plan with a budget of approximately $23 million. TEP cannot predict the outcome of the proceeding.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.
The table below summarizes the LFCR revenues recognized in Operating Revenues on the Consolidated Statements of Income:
Years Ended December 31,
(in millions) 2020 2019 2018
LFCR Revenues $ 46 $ 33 $ 26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below:
Remaining Recovery Period (years) December 31,
($ in millions) 2020 2019
Regulatory Assets
Pension and Other Postretirement Benefits (Note 10) Various $ 166 $ 135
Lost Fixed Cost Recovery 2 59 46
Derivatives (Note 13) 9 55 72
Early Generation Retirement Costs Various 43 68
Income Taxes Recoverable through Future Rates (1)
Various 27 38
Property Tax Deferrals (2)
1 26 24
Under Recovered Purchased Energy Costs 1 23 36
Final Mine Reclamation and Retiree Healthcare Costs (3)
8 20 19
Springerville Unit 1 Leasehold Improvements (4)
3 7 9
Other Regulatory Assets Various 16 18
Total Regulatory Assets 442 465
Less Current Portion 1 124 138
Total Non-Current Regulatory Assets $ 318 $ 327
Regulatory Liabilities
Income Taxes Payable through Future Rates (1)
Various $ 298 $ 327
Net Cost of Removal (5)
Various 125 164
Renewable Energy Standard Various 63 59
Tax Reform Bill Credit Various 29 8
Transmission Revenue Subject to Refund-FERC
Various 15 4
Deferred Investment Tax Credits (6)
Various 2 3
Other Regulatory Liabilities Various 9 8
Total Regulatory Liabilities 541 573
Less Current Portion 1 151 96
Total Non-Current Regulatory Liabilities $ 390 $ 477
(1)Amortized over the lives of the assets. See Note 1 and Note 14 for additional information regarding income taxes.
(2)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. This asset is fully recovered in rates with a recovery period of approximately six months.
(3)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. The majority of final mine reclamation costs are expected to be funded by TEP through 2028.
(4)Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.
(5)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. As part of the 2020 Rate Order, Net Cost of Removal of $22 million related to Sundt Units 1 and 2 was reclassified to Early Generation Retirement Costs in Regulatory and Other Assets-Regulatory Assets on the Consolidated Balance Sheets.
(6)Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Early Generation Retirement Costs
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension allowing TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the co-owners of Navajo retired the generation station in November 2019, with related decommissioning activities continuing through 2054. TEP has historically recovered the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, TEP received approval to recover final retirement costs over a 10-year period in the 2020 Rate Order. As of December 31, 2020, Navajo's regulatory asset balance was $41 million.
Sundt Generating Station
In 2018, the Pima County Department of Environmental Quality approved TEP's air permit application. Under the project outlined in the application, TEP placed in service 10 RICE units and was required to retire Sundt Units 1 and 2 in November 2019. TEP has historically recovered the capital and operating costs in base rates using useful lives of 2028 and 2030 for Sundt Units 1 and 2, respectively. Due to the early retirement, TEP received approval to recover final retirement costs over a 10-year period in the 2020 Rate Order. As of December 31, 2020, Sundt Units 1 and 2's regulatory asset balance was $2 million. See Note 3 for additional information on the RICE units.
Regulatory Assets and Liabilities
Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. TEP pays a return on the majority of its regulatory liability balances.
IMPACTS OF REGULATORY ACCOUNTING
If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.
NOTE 3. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Plant in Service on the Consolidated Balance Sheets by major class:
Annual Depreciation Rate (4)
Average Remaining Life in Years (4)
December 31,
($ in millions) 2020 2019
Plant in Service
Generation Plant 3.19% 19 $ 3,279 $ 3,065
Transmission Plant (1)
1.69% 36 1,090 1,060
Distribution Plant 1.56% 30 1,906 1,784
General Plant 5.89% 19 503 477
Intangible Plant, Software Costs, and Other (2)
Various Various 291 271
Plant Held for Future Use - - 4 7
Total Plant in Service (3)
$ 7,073 $ 6,664
(1)TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 2019 FERC Rate Case.
(2)Primarily represents computer software. Unamortized computer software costs were $74 million and $78 million as of December 31, 2020 and 2019, respectively. Amortized computer software costs were $29 million in 2020, $26 million in 2019, and $24 million in 2018. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of two years for large enterprise software.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(3)Includes plant acquisition adjustments of $(202) million and $(211) million as of December 31, 2020 and 2019, respectively.
(4)Based on the 2015 depreciation study available for the major classes of Plant in Service, effective March 1, 2017, as approved by the ACC as part of the 2017 Rate Order. TEP implemented new depreciation rates for all major classes, except transmission, based on the 2018 depreciation study, effective January 1, 2021, as approved by the ACC as part of the 2020 Rate Order.
Springerville Common Facilities
In December 2020, due to the pending expiration of leases, TEP purchased 32.2% in undivided interests in the Springerville Common Facilities at a total fixed purchase price of $68 million. Also in December 2020, SRP, the owner of Springerville Unit 4, purchased a 14% undivided interest in the Springerville Common Facilities for $30 million. The transactions resulted in an increase in Plant in Service and a decrease in Utility Plant Under Finance Leases on the Consolidated Balance Sheets. TEP's total undivided ownership interest in the Springerville Common Facilities totaled 86% as of December 31, 2020.
Tri-State, the lessee of Springerville Unit 3, is obligated to either: (i) buy a 14% undivided interest in the facilities for $30 million; or (ii) continue to make payments to TEP for the use of these facilities. Tri-State has until December 2021 to exercise its purchase option.
Gila River Unit 2
In 2017, TEP entered into the Tolling PPA. The Tolling PPA was accounted for as a finance lease. In December 2019, TEP completed its purchase of Gila River Unit 2 for $165 million. The purchase increased Plant in Service and Material and Supplies and decreased Utility Plant Under Finance Leases on the Consolidated Balance Sheets as of December 31, 2019.
RICE Units
Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed in service five natural gas RICE units in December 2019 and an additional five units in March 2020. There was $187 million as of December 31, 2020, and $82 million as of December 31, 2019, related to the Sundt RICE units recorded in Plant in Service on the Consolidated Balance Sheets. The 10 units have a total nominal generation capacity of 188 MW.
JOINTLY-OWNED FACILITIES
As of December 31, 2020, TEP was a participant in the following jointly-owned generation facilities and transmission systems:
($ in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value
San Juan Unit 1 50.0% $ 289 $ 1 $ (239) $ 51
Four Corners Units 4 and 5 7.0% 181 4 (76) 109
Luna 33.3% 58 - (2) 56
Gila River Unit 3 75.0% 204 - (62) 142
Gila River Common Facilities 43.8% 73 1 (25) 49
Springerville Coal Handling Facilities 83.0% 211 - (95) 116
Springerville Common Facilities 86.0% 397 - (197) 200
Transmission Facilities Various 547 15 (298) 264
Total $ 1,960 $ 21 $ (994) $ 987
As a participant in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ASSET RETIREMENT OBLIGATIONS
The liability accrual of AROs is primarily related to generation and PV 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) 2020 2019
Beginning of Period $ 107 $ 72
Liabilities Settled (1)
(5) (2)
Regulatory Deferral/Accretion Expense 4 2
Revisions to the Present Value of Estimated Cash Flows (2)
(10) 35
End of Period $ 96 $ 107
(1)Primarily related to the retirement of Navajo.
(2)Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of certain generation facilities and changes in ownership of Springerville Common Facilities.
NOTE 4. REVENUE
TEP earns the majority 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.
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) 2020 2019 2018
Retail $ 1,039 $ 972 $ 1,022
Wholesale 190 247 238
Other Services 95 124 100
Revenues from Contracts with Customers 1,324 1,343 1,360
Alternative Revenues 48 35 28
Other 53 40 45
Total Operating Revenues $ 1,425 $ 1,418 $ 1,433
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 the spring and summer months and decrease during the 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, Net on the Consolidated Balance Sheets.
In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. See Note 2 for more information regarding the 2020 Rate Order.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the 2019 FERC rate case.
Other Services Revenues
Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, miscellaneous service-related revenues, and reimbursement of various operating expenses for the use of the Springerville Common Facilities by Springerville Units 3 and 4 and the Springerville Coal Handling Facilities by Springerville Unit 3. When TEP recognizes revenue for reimbursement of Springerville Common Facilities and Springerville Coal Handling Facilities' operating expenses, the associated expenses are recorded in their respective line items on the income statement based on the nature of services provided.
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 mechanism and DSM performance incentive as alternative revenues. The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of applicable retail revenues of 2%. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding these cost recovery mechanisms.
Other Revenues
Other Revenues include gains and losses on derivative contracts, common cost allocations to affiliates, and asset management agreement service fees and optimization gains. See Note 6 for information regarding revenue from related parties and Note 13 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) 2020 2019
Retail $ 90 $ 61
Retail, Unbilled 41 42
Retail, Allowance for Credit Losses (1)
(13) (6)
Wholesale (2)
33 31
Due from Affiliates (Note 6)
9 8
Other 13 19
Accounts Receivable $ 173 $ 155
(1)In 2019, prior to adoption of the current expected credit loss guidance, this line was presented as Allowance for Doubtful Accounts. See Note 1 for information regarding the adoption of the current expected credit loss guidance.
(2)Includes $7 million and $5 million as of December 31, 2020 and 2019, 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 following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Consolidated Balance Sheets:
Year Ended December 31,
(in millions) 2020
Beginning of Period $ (6)
Credit Loss Expense (10)
Write-offs 3
End of Period $ (13)
Service Disconnection Moratoriums
In 2019, the ACC enacted emergency rules that suspended service disconnections and late fees for electric residential customers who would have otherwise been eligible for service disconnection during the period from June 1 through October 15 (Summer Moratorium). The Summer Moratorium remained in effect for 2020 and will remain in effect each year until the ACC permanently adopts new rules regarding electric service disconnections. In addition, TEP voluntarily suspended service disconnections and late fees beginning March 2020 for all customers who would have otherwise been disconnected and continued the moratorium through December 31, 2020.
In December 2020, the ACC enacted a bill credit and payment program for residential customers who are behind on their electric bills as a result of the COVID-19 pandemic. For qualifying customers the program included: (i) an upfront bill credit applied to their December 2020 bill; and (ii) automatic enrollment into an eight-month payment plan. TEP also voluntarily created payment arrangements for commercial customers.
As a result of the moratoriums, TEP has increased its credit loss reserve by $7 million as of December 31, 2020, compared to December 31, 2019. TEP is continuing to monitor collection activity and adjusting its allowance for credit losses as needed.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW CREDIT LOSSES STANDARD
TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows:
Years Ended December 31,
(in millions) 2019 2018
Beginning of Period $ (5) $ (5)
Additions Charged to Cost and Expense (4) (3)
Write-offs 3 3
End of Period $ (6) $ (5)
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. Effective January 1, 2021, TEP hired SES' employees and will no longer utilize SES' labor-related services.
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) 2020 2019
Receivables from Related Parties
UNS Electric $ 6 $ 6
UNS Energy 2 -
UNS Gas 1 2
Total Due from Related Parties $ 9 $ 8
Payables to Related Parties
SES $ 4 $ 2
UNS Energy 1 1
UNS Electric - 1
Total Due to Related Parties $ 5 $ 4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the components of related party transactions included in the Consolidated Statements of Income:
Years Ended December 31,
(in millions) 2020 2019 2018
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)
$ 9 $ 7 $ 6
Wholesale Revenues, UNS Electric (1)
1 1 1
Control Area Services, UNS Electric (2)
4 4 3
Common Costs, UNS Energy Affiliates (3)
19 19 18
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (4)
14 15 15
Corporate Services, UNS Energy (5)
5 6 6
Corporate Services, UNS Energy Affiliates (6)
4 4 7
Capacity Charges, UNS Gas (7)
- 1 1
Corporate Services, Fortis Affiliates (8)
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)TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.
(3)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.
(4)SES provided supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges were based on cost of services performed and deemed reasonable by management.
(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 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $6 million in 2020, $6 million in 2019, and $5 million in 2018.
(6)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
(7)UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.
(8)Fortis charges TEP for its share of payroll tax, insurance, and other costs paid by Fortis for affiliated employees.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 7. DEBT AND CREDIT AGREEMENTS
DEBT
Long-term debt matures more than one year from the date of debt issuance. The following table presents the components of Long-Term Debt which includes Long-Term Debt, Net and Current Maturities of Long-Term Debt, Net on the Consolidated Balance Sheets:
December 31,
($ in millions) Interest Rate Maturity Date 2020 2019
Notes
2011 Senior Notes (1)
5.15% 2021 $ 250 $ 250
2012 Senior Notes 3.85% 2023 150 150
2014 Senior Notes 5.00% 2044 150 150
2015 Senior Notes 3.05% 2025 300 300
2018 Senior Notes 4.85% 2048 300 300
2020 Senior Notes 4.00% 2050 350 -
2020 Senior Notes 1.50% 2030 300 -
Tax-Exempt Local Furnishings Bonds (2)
2010 Pima A 5.25% 2040 - 100
2012 Pima A 4.50% 2030 16 16
2013 Pima A 4.00% 2029 91 91
Tax-Exempt Pollution Control Bonds (3)
2009 Pima A 4.95% 2020 - 80
2012 Apache A 4.50% 2030 177 177
Total Long-Term Debt (4)
2,084 1,614
Less Unamortized Discount and Debt Issuance Costs 20 12
Less Current Maturities of Long-Term Debt 250 80
Total Long-Term Debt, Net $ 1,814 $ 1,522
(1)The TEP 2011 Notes become callable at par on or after August 15, 2021 and are due on November 15, 2021.
(2)The 2012 Pima A bonds become callable at par in the second quarter of 2022. The 2013 Pima A bonds become callable at par in the first quarter of 2023.
(3)The 2012 Apache A bonds become callable at par in the first quarter of 2022.
(4)As of December 31, 2020, all of TEP's debt is unsecured.
Issuances and Redemptions
In September 2020, TEP extinguished its obligations on two series of fixed rate tax-exempt bonds with aggregate principal amounts of: (i) $80 million, which matured on October 1, 2020; and (ii) $100 million redeemed at par on October 1, 2020, the first par call date.
In August 2020, TEP issued and sold $300 million aggregate principal amount of 1.50% senior unsecured notes due August 2030. The debt is callable prior to May 1, 2030, with a make-whole premium plus accrued interest. After May 1, 2030, the debt becomes callable at par plus accrued interest. An amount equal to the net proceeds was allocated to the total costs of Oso Grande.
In April 2020, TEP issued and sold $350 million aggregate principal amount of 4.00% senior unsecured notes due June 2050. The debt is callable prior to December 15, 2049, with a make-whole premium plus accrued interest. After December 15, 2049,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the debt becomes callable at par plus accrued interest. TEP used the net proceeds from the sale to repay amounts outstanding under its credit agreements and for general corporate purposes.
In November 2019, TEP redeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of $15 million prior to the maturity of the bonds.
Maturities
Long-term debt matures on the following dates:
(in millions) Long-Term Debt (1)
2021 $ 250
2022 -
2023 150
2024 -
2025 300
Thereafter 1,384
Total $ 2,084
(1)Total long-term debt excludes $14 million of related unamortized debt issuance costs and $6 million of unamortized original issue discount.
CREDIT AGREEMENTS
Amounts borrowed under credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets.
2019 Credit Agreement
In December 2019, TEP entered into an unsecured credit agreement with a maturity date of December 2020 that provided for $225 million in term loans (2019 Credit Agreement). Amounts borrowed from the 2019 Credit Agreement were used: (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. As of December 31, 2019, there was $60 million available under the 2019 Credit Agreement. In April 2020, TEP used the net proceeds from the sale of senior unsecured notes to repay $225 million in outstanding term loans and terminated such agreement.
2015 Credit Agreement
In October 2015, TEP entered into an unsecured credit agreement with a maturity date of October 2022 that provides for revolving credit commitments and LOC facilities. Terms are as follows:
Capacity Sub-Limit LOC Borrowed (1)
Available Weighted Average Interest Rate Pricing (2)
($ in millions) December 31, 2020
Revolver and LOC $ 250 $ 50 $ 12 $ 238 - % LIBOR + 1.000% or ABR + 0.00%
($ in millions) December 31, 2019
Revolver and LOC $ 250 $ 50 $ - $ 250 - % LIBOR + 1.000% or ABR + 0.00%
(1)Includes $12 million in LOCs at a rate of 1.00% per annum issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the BTA.
(2)Interest rates and fees are based on a pricing grid tied to TEP's credit rating.
Amounts borrowed under the 2015 Credit Agreement will be 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 8. LEASES
TEP’s leases are included on the balance sheet as follows:
December 31,
(in millions) Lease Type 2020 2019
Lease Assets
Utility Plant Under Finance Leases Finance $ - $ 151
Accumulated Amortization of Finance Lease Assets Finance - (77)
Regulatory and Other Assets, Other Operating 8 8
Lease Liabilities
Current Liabilities, Finance Lease Obligations Finance - 17
Finance Lease Obligations Finance - 67
Current Liabilities, Other Operating 1 1
Regulatory and Other Liabilities, Other Operating 7 6
OPERATING LEASES
TEP leases office facilities, land, rail cars, and communication tower space with remaining terms of two to 21 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 10 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.
FINANCE LEASES
Springerville Common Facilities Leases
TEP financed the Springerville Common Facilities with leases. In December 2020, TEP purchased undivided interests in the Springerville Common Facilities prior to the expiration of the leases in January 2021. See Note 3 for additional information about TEP's purchase.
Gila River Unit 2
In 2017, TEP entered into a Tolling PPA. The Tolling PPA was accounted for as a finance lease. In December 2019, TEP completed its purchase of Gila River Unit 2. See Note 3 for additional information about TEP's purchase.
LEASE COST
The following table presents the components of TEP’s lease cost:
Years Ended December 31,
(in millions) 2020 2019
Finance
Amortization of Leased Assets (1)
$ 10 $ 13
Interest on Lease Liabilities (2)
2 13
Operating 1 1
Variable (3)
2 16
Short Term 1 1
Total Lease Cost $ 16 $ 44
(1)Finance lease amortization is recorded in Depreciation on the Consolidated Statements of Income. In 2020, TEP deferred $2 million of amortization related to the Springerville Common Facilities in Regulatory and Other Assets -Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. TEP deferred $6 million of amortization related to Gila River Unit 2 in Regulatory and Other Assets-Regulatory Assets on the Consolidated Balance Sheets based on PPFAC recovery of TEP's fixed capacity payment in 2019.
(2)In 2020, TEP deferred $1 million of lease interest expense related to the Springerville Common Facilities in Regulatory and Other Assets -Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. Finance lease interest expense related to Gila River Unit 2 was $12 million in 2019.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(3)With the purchase of Gila River Unit 2 in 2019, TEP ceased paying the monthly operating fee to compensate SRP for the non-fuel costs of operating the unit under the Tolling PPA. The operating fees represented variable lease costs included in Purchased Power on the Consolidated Statements of Income.
TEP's operating lease cost was $1 million in 2018.
TEP has a 20-year lease for battery storage with variable payments contingent on performance, which is expected to commence by the second quarter of 2021.
MATURITY ANALYSIS OF LEASE LIABILITIES
As of December 31, 2020, TEP's future minimum lease payments, excluding payments to lessors for variable costs, follow:
(in millions) Operating Leases
2021 $ 1
2022 1
2023 1
2024 1
2025 1
Thereafter 4
Total Lease Payments 9
Less Imputed Interest 1
Total Lease Obligations 8
Less Current Portion 1
Total Non-Current Lease Obligations $ 7
LEASE TERMS AND DISCOUNT RATES
The following table presents TEP's lease terms and discount rates related to its leases:
December 31,
2020 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases - 1
Operating Leases 11 12
Weighted-Average Discount Rate
Finance Leases - % 2.2 %
Operating Leases 3.9 % 4.1 %
LEASE CASH FLOWS
The following table presents cash paid for amounts included in the measurement of lease liabilities:
Years Ended December 31,
(in millions) 2020 2019
Operating Cash Flows used for Finance Leases $ 1 $ 13
Operating Cash Flows used for Operating Leases 1 1
Financing Cash Flows used for Finance Leases 17 11
Investing Cash Flows used for Finance Leases 68 164
See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.
LEASE INCOME
TEP leases limited office facilities and utility property to others with remaining terms of three to 22 years. Most leases include one or more options to renew with renewal terms that may extend a lease term for up to three years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP's operating lease income was $1 million in each of 2020 and 2019 included in Other, Net on the Consolidated Statements of Income. TEP's expected operating lease payments to be received as of December 31, 2020, are $1 million or less in each of 2021 through 2025 and $3 million thereafter.
NOTE 9. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As of December 31, 2020, TEP had the following commitments:
(in millions) 2021 2022 2023 2024 2025 Thereafter Total
Minimum Purchase Commitments
Fuel, Including Transportation $ 88 $ 67 $ 36 $ 36 $ 28 $ 169 $ 424
Purchased Power 11 - - - - - 11
Transmission 27 27 17 12 11 8 102
Purchase Commitments
Renewable Power Purchase Agreements 63 63 63 62 62 481 794
RES Performance-Based Incentives 7 7 7 7 5 28 61
Build-Transfer Agreement 19 - - - - - 19
Total Commitments $ 215 $ 164 $ 123 $ 117 $ 106 $ 686 $ 1,411
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 between 2022 and 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 transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2022 and 2040.
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 fourth quarter of 2021. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2020.
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 2021 and 2030.
Purchase Commitments
Renewable Power Purchase Agreements
TEP enters into long-term renewable PPAs which requires 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 2036.
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 2021 and 2034.
Build-Transfer Agreement
Oso Grande is estimated to cost $436 million, which includes, among other costs, $27 million for AFUDC and $397 million related to the BTA. TEP made payments under the BTA of $47 million in 2019 and $331 million in 2020, and is expected to pay the remaining $19 million in 2021 to fulfill TEP's commitment. As of December 31, 2020, project costs incurred were included in Construction Work in Progress on the Consolidated Balance Sheets. On February 2, 2021, TEP made a payment of $10 million for Oso Grande under the BTA.
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 coal supply agreements’ terms. TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP defers these expenses until recovered from customers by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid.
TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of final mine reclamation costs at both mines is $48 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $40 million and $36 million as of December 31, 2020 and 2019, respectively, was recorded in Other on the Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.
Performance Guarantees
TEP has joint generation participation agreements with participants at San Juan, Four Corners, and Luna, which expire in 2022, 2041, and 2046, respectively. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generation facility. The participants in each of the generation facilities, 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. Relative to Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of December 31, 2020, there have been no such payment defaults under any of the participation agreements.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Broadway-Pantano Site
The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized.
NOTE 10. 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 $1 million in 2020, $1 million in 2019, and $3 million in 2018 to the VEBA. 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 Other Comprehensive Income (Loss) since SERP expense is not currently recoverable in rates.
The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the balance sheet:
Pension Benefits Other Postretirement Benefits
December 31,
(in millions) 2020 2019 2020 2019
Regulatory Assets $ 150 $ 135 $ 16 $ -
Regulatory Liabilities - - - (1)
Accrued Employee Expenses (1) (2) (3) (2)
Pension and Other Postretirement Benefits (91) (77) (72) (56)
Accumulated Other Comprehensive Loss, SERP 14 10 - -
Net Amount Recognized $ 72 $ 66 $ (59) $ (59)
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, 2020 and 2019. The table below presents the status of all of TEP’s pension and other postretirement benefit plans.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented:
Pension Benefits Other Postretirement Benefits
Years Ended December 31,
(in millions) 2020 2019 2020 2019
Change in Benefit Obligation
Beginning of Period $ 525 $ 440 $ 79 $ 74
Actuarial (Gain) Loss 76 76 18 4
Interest Cost 16 18 3 3
Service Cost 16 13 4 4
Benefits Paid (27) (23) (5) (6)
Plan Amendments - 1 - -
End of Period 606 525 99 79
Change in Fair Value of Plan Assets
Beginning of Period 446 376 21 17
Actual Return on Plan Assets 78 81 3 4
Benefits Paid (26) (22) (5) (6)
Employer Contributions (1)
16 11 5 6
End of Period 514 446 24 21
Funded Status at End of Period $ (92) $ (79) $ (75) $ (58)
(1)TEP expects to contribute $13 million to the pension plans and $1 million to the VEBA trust in 2021.
The $81 million increase in the Pension Benefits obligation was driven by a significant decrease in discount rates as a result of a decrease in interest rates. The $68 million increase in the Pension Benefits plan assets was due to positive equity returns and fixed income returns as a result of a decline in interest rates. The $20 million increase in the Other Postretirement Benefits obligation was driven by a decrease in the discount rate and an increase in premium rates.
The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:
Pension Benefits Other Postretirement Benefits
Years Ended December 31,
(in millions) 2020 2019 2020 2019
Net Loss $ 164 $ 145 $ 18 $ 1
Prior Service Cost (Benefit) 1 - (2) (2)
The accumulated benefit obligation aggregated for all pension plans was $545 million and $476 million as of December 31, 2020 and 2019, respectively. All of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2020 and 2019. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:
December 31,
(in millions) 2020 2019
Accumulated Benefit Obligation $ 545 $ 476
Fair Value of Plan Assets 514 446
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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) 2020 2019 2018 2020 2019 2018
Service Cost $ 16 $ 13 $ 15 $ 4 $ 4 $ 5
Non-Service Cost
Interest Cost 16 18 16 3 3 2
Expected Return on Plan Assets (30) (26) (28) (2) (2) (1)
Amortization of Net (Gain) Loss 8 8 7 - - -
Net Periodic Benefit Cost $ 10 $ 13 $ 10 $ 5 $ 5 $ 6
The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. In 2020, TEP capitalized 22% of service cost as a cost of construction, 21% in 2019, and 19% in 2018 .
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows:
Pension Benefits Other Postretirement Benefits
Regulatory Asset AOCI Regulatory Asset
(in millions) 2020 2019 2018 2020 2019 2018 2020 2019 2018
Current Year Actuarial (Gain) Loss $ 23 $ 16 $ 12 $ 5 $ 4 $ (1) $ 17 $ 1 $ (6)
Amortization of Net Loss (8) (8) (7) (1) (1) - - - -
Prior Service (Credit) Cost - - - - 1 (1) - - (2)
Total Recognized (Gain) Loss $ 15 $ 8 $ 5 $ 4 $ 4 $ (2) $ 17 $ 1 $ (8)
For all pension plans, TEP amortizes prior service costs 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 with regard to 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.
The following table includes the weighted average assumptions used to determine benefit obligations:
Pension Benefits Other Postretirement Benefits
2020 2019 2020 2019
Discount Rate 2.9% 3.6% 2.6% 3.3%
Rate of Compensation Increase 2.8% 2.8% N/A N/A
The following table includes the weighted average assumptions used to determine net periodic benefit costs:
Pension Benefits Other Postretirement Benefits
2020 2019 2018 2020 2019 2018
Discount Rate, Service Cost 3.8% 4.7% 3.8% 3.5% 4.5% 3.8%
Discount Rate, Interest Cost 3.1% 4.2% 3.4% 2.9% 4.0% 3.2%
Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A
Expected Return on Plan Assets 6.8% 7.0% 7.0% 7.0% 7.0% 7.0%
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:
December 31,
2020 2019
Next Year (Pre-65) 6.1% 6.3%
Next Year (Post-65) 7.1% 7.5%
Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5%
Year Ultimate Rate is Reached (Pre-65) 2037 2037
Year Ultimate Rate is Reached (Post-65) 2037 2037
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
2020 2019 2020 2019
Asset Category
Equity Securities 47 % 46 % 63 % 65 %
Fixed Income Securities 45 % 45 % 35 % 33 %
Real Estate 7 % 8 % - % - %
Other 1 % 1 % 2 % 2 %
Total 100 % 100 % 100 % 100 %
As of December 31, 2020, the fair value of VEBA trust assets was $24 million, of which $9 million were fixed income investments and $15 million were equities. As of December 31, 2019, the fair value of VEBA trust assets was $21 million, of which $7 million were fixed income investments and $14 million were equities. The VEBA trust assets are primarily Level 2 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust.
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, 2020
Asset Category
Equity Securities:
United States Large Cap $ - $ 65 $ - $ 65
United States Small Cap - 25 - 25
Non-United States - 95 - 95
Global - 59 - 59
Fixed Income - 231 - 231
Real Estate - 12 23 35
Private Equity - - 4 4
Total $ - $ 487 $ 27 $ 514
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions) December 31, 2019
Asset Category
Cash Equivalents $ 2 $ - $ - $ 2
Equity Securities:
United States Large Cap - 55 - 55
United States Small Cap - 21 - 21
Non-United States - 80 - 80
Global - 51 - 51
Fixed Income - 199 - 199
Real Estate - 10 23 33
Private Equity - - 5 5
Total $ 2 $ 416 $ 28 $ 446
•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 similar properties.
•Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
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, 2018 $ 6 $ 22 $ 28
Actual Return on Plan Assets:
Assets Held at Reporting Date 1 1 2
Purchases, Sales, and Settlements (2) - (2)
Balance as of December 31, 2019 5 23 28
Actual Return on Plan Assets:
Assets Held at Reporting Date - - -
Purchases, Sales, and Settlements (1) - (1)
Balance as of December 31, 2020 $ 4 $ 23 $ 27
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 in light of 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 in order 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 as a whole. 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.
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, 2020
Cash/Treasury Bills -% 2%
Equity Securities:
United States Large Cap 14% 39%
United States Small Cap 5% 5%
Non-United States Developed -% 7%
Non-United States Emerging -% 9%
Global Equity 29% -%
Global Infrastructure 3% -%
Fixed Income 40% 38%
Real Estate 8% -%
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-parties’ 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) 2021 2022 2023 2024 2025 2026-2030
Pension Benefits $ 28 $ 28 $ 29 $ 28 $ 29 $ 154
Other Postretirement Benefits 6 6 6 6 6 28
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 $6 million in 2020 and 2019 and $7 million in 2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 11. 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 RSU 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.
The following table represents RSUs awarded by Fortis for UNS Energy:
RSUs 15,751
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 $1 million as of December 31, 2020.
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 2020 based on its share of UNS Energy's 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:
2020 2019 2018
PSUs 35,328 66,978 54,426
RSUs (1)
1,918 33,489 27,213
(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 $10 million and $12 million as of December 31, 2020 and 2019, 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 2020, $4 million in 2019, and $2 million in 2018 based on its share of UNS Energy's compensation expense.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 12. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS
Years Ended December 31,
(in millions) 2020 2019 2018
Interest Paid, Net of Amounts Capitalized $ 76 $ 80 $ 67
Income Tax Refunds (1)
(14) (14) -
(1)TEP received refunds of AMT credit carryforwards in 2020 and 2019. See Note 14 for additional information regarding AMT.
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) 2020 2019 2018
Accrued Capital Expenditures $ 26 $ 40 $ 31
Renewable Energy Credits 3 3 3
Operating Leases (1)
1 8 -
Finance Leases - 67 164
Asset Retirement Obligations Increase (Decrease) (2)
(12) 26 20
Net Cost of Removal Increase (Decrease) (3)
(34) (10) (4)
(1)In 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods.
(2)The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of expected future AROs.
(3)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings.
NOTE 13. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:
Level 1 Level 2 Total
(in millions) December 31, 2020
Assets
Restricted Cash (1)
$ 21 $ - $ 21
Energy Derivative Contracts, Regulatory Recovery (2)
- 14 14
Energy Derivative Contracts, No Regulatory Recovery (2)
- 3 3
Total Assets 21 17 38
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
- (66) (66)
Total Liabilities - (66) (66)
Total Assets (Liabilities), Net $ 21 $ (49) $ (28)
(in millions) December 31, 2019
Assets
Restricted Cash (1)
$ 18 $ - $ 18
Energy Derivative Contracts, Regulatory Recovery (2)
- 3 3
Energy Derivative Contracts, No Regulatory Recovery (2)
- 3 3
Total Assets 18 6 24
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
- (76) (76)
Total Liabilities - (76) (76)
Total Assets (Liabilities), Net $ 18 $ (70) $ (52)
(1)Restricted Cash represents amounts held in money market funds, which approximates 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 purchased power and sales 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 on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:
Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount
Counterparty Netting of Energy Contracts Cash Collateral Received/Posted
(in millions) December 31, 2020
Derivative Assets
Energy Derivative Contracts $ 17 $ 14 $ - $ 3
Derivative Liabilities
Energy Derivative Contracts (66) (14) (7) (45)
(in millions) December 31, 2019
Derivative Assets
Energy Derivative Contracts $ 6 $ 4 $ - $ 2
Derivative Liabilities
Energy Derivative Contracts (76) (4) (2) (70)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 the Company's retail customers.
TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and 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 the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:
Years Ended December 31,
(in millions) 2020 2019 2018
Unrealized Net Gain (Loss) (1)
$ 21 $ (45) $ (9)
(1)In 2020, unrealized net gain on regulatory recoverable derivative contracts increased primarily due to increases in forward market prices of natural gas and the settlement of contracts.
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, as defined 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) 2020 2019 2018
Operating Revenues $ 5 $ 6 $ 5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Derivative Volumes
As of December 31, 2020, 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,
2020 2019
Power Contracts GWh 4,143 4,740
Gas Contracts BBtu 111,585 122,779
Level 3 Fair Value Measurements
As of December 31, 2020, TEP did not have any Level 3 assets and liabilities balances. The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held:
Year Ended December 31,
(in millions) 2019
Beginning of Period $ 1
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments (12)
Operating Revenues 5
Settlements 1
Transfers Out of Level 3 (1)
End of Period $ -
Gains (Losses), Assets (Liabilities) Still Held $ -
(1)Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities.
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 certain 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 counterparties' assessment of TEP's credit strength. In the event that such credit events were to occur, TEP, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.
TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the 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 $60 million as of December 31, 2020, compared with $100 million as of December 31, 2019. As of December 31, 2020, TEP had $7 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets-Other on the Consolidated Balance Sheets. If the credit risk contingent features were triggered on December 31, 2020, TEP would have been required to post an additional $53 million of collateral of which $19 million relates to outstanding net payable balances for settled positions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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) 2020 2019 2020 2019
Liabilities
Long-Term Debt, including Current Maturities Level 2 $ 2,064 $ 1,602 $ 2,363 $ 1,755
NOTE 14. 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) 2020 2019 2018
Federal Income Tax Expense at Statutory Rate $ 49 $ 46 $ 49
State Income Tax Expense, Net of Federal Deduction 9 9 9
Federal/State Tax Credits (3) (6) (10)
Allowance for Equity Funds Used During Construction (7) (3) (1)
Excess Deferred Income Taxes (7) (9) (6)
Impact of AMT Sequestration (1)
- (2) 2
Other - (1) -
Total Federal and State Income Tax Expense $ 41 $ 34 $ 43
(1)In 2018, the Company recorded $2 million of income tax expense related to the estimated impact of sequestration on future AMT credit refunds, which it then reversed in 2019 when the IRS revised the guidance and the AMT credit refunds were no longer subject to sequestration.
Income Tax Expense included on the Consolidated Statements of Income consists of the following:
Years Ended December 31,
(in millions) 2020 2019 2018
Current Income Tax Expense
Federal $ (2) $ (8) $ (13)
State 1 - -
Total Current Income Tax Expense (1) (8) (13)
Deferred Income Tax Expense
Federal 37 41 53
Federal Investment Tax Credits (1) (4) (6)
State 6 5 9
Total Deferred Income Tax Expense 42 42 56
Total Federal and State Income Tax Expense $ 41 $ 34 $ 43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017.
In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $7 million and $9 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively. As part of the 2020 Rate Order, TEP received approval of a TEAM that allows income tax changes that materially affect TEP’s authorized revenue requirement to be shared with customers including changes in EDIT amortization. Effective January 1, 2021, TEP will share any changes in its EDIT amortization through the new cost adjustor. See Note 2 for additional information regarding the ACC Refund Order and cost adjustors.
Under the TCJA, existing AMT credit carryforwards could be refunded or used to offset U.S. federal income tax liabilities through our 2021 tax year. Along with other significant provisions, the CARES Act accelerated the recovery of remaining AMT credits by allowing corporations to immediately claim refunds of all unused carryforward balances. In 2020, TEP received AMT credit refunds of $14 million recorded to Current Assets-Other on the Consolidated Balance Sheets. As of December 31, 2019, $7 million was recorded as a receivable in Current Assets-Other on the Consolidated Balance Sheets related to AMT credit refunds.
The significant components of deferred income tax assets and liabilities consist of the following:
December 31,
(in millions) 2020 2019
Gross Deferred Income Tax Assets
Finance Lease Obligations (1)
$ - $ 21
Operating Loss Carryforwards, Net - 3
Customer Advances and Contributions in Aid of Construction 19 19
AMT Credit - 7
Other Postretirement Benefits 15 15
Investment Tax Credit Carryforward 19 34
Income Taxes Payable Through Future Rates 74 81
Other 76 79
Total Gross Deferred Income Tax Assets 203 259
Deferred Tax Assets Valuation Allowance - -
Gross Deferred Income Tax Liabilities
Plant, Net (639) (602)
Plant Abandonments (11) (17)
Finance Lease Assets, Net (1)
- (18)
Pensions (17) (17)
Income Taxes Recoverable Through Future Rates (7) (9)
Other (22) (28)
Total Gross Deferred Income Tax Liabilities (696) (691)
Deferred Income Taxes, Net $ (493) $ (432)
(1)In December 2020, TEP purchased an undivided interest in the Springerville Common Facilities prior to the expiration of its leases in January 2021. See Note 3 for additional information about TEP's purchase.
TEP recorded no valuation allowance against all other tax credit and net operating loss carryforward deferred income tax assets as of December 31, 2020 and 2019. 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, 2020, TEP had the following carryforward amounts:
($ in millions) Amount Expiring Year
State Credits $ 7 2022 - 29
Investment Tax Credits 19 2034 - 40
Other Federal Credits 1 2034 - 40
UNCERTAIN TAX POSITIONS
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
December 31,
(in millions) 2020 2019
Beginning of Period $ 18 $ 16
Additions Based on Tax Positions Taken in the Current Year 1 2
End of Period $ 19 $ 18
Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 2020 and 2019.
TEP recorded no interest expense in 2020 and 2019 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2020 and 2019.
TEP has been audited by the IRS through tax year 2010. TEP's 2011 to 2019 tax years are open for audit by federal and state tax agencies.
TEP had previously filed an application with the IRS for a change in accounting method on uncertain tax positions. On February 2, 2021, TEP received approval of this application from the IRS which will result in a $17 million decrease in uncertain tax position obligations on a prospective basis.
TAX SHARING AGREEMENT
Under the terms of the tax sharing agreement with UNS Energy, TEP received $14 million in 2020 and 2019 related to Federal income tax returns for 2019 and 2018, respectively.

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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, 2020.
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, 2020. 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, 2020, 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 2020 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.
PART III

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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 (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) 2020 2019
Audit Fees (1)
$ 1,027 $ 1,040
Audit-Related Fees (2)
45 21
Tax Fees (3)
- 25
Total $ 1,072 $ 1,086
(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 2020 and 2019.
(3)Tax Fees are fees billed by Deloitte for professional services related to tax planning and tax strategy.
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, 2020 and 2019, and for each of the three years in the period ended December 31, 2020:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income
Consolidated Statements of Comprehensive 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 90.