UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 110-K
(Mark One)
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20212022
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
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| Arizona | 86-0062700 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
88 East Broadway Boulevard, Tucson, AZ 85701
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, No Par Value (Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ox No xo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large Accelerated Filer o ☐ | Accelerated Filer ☐ | Accelerated Filer o
| Non-Accelerated Filer | ☒x | Smaller Reporting Company | ☐ | | Emerging Growth Company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐o
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ Nox
State the aggregate market value of the voting and non-voting common equity held by non-affiliates:non-affiliates, as of the last business day of the registrant’s most recently completed second fiscal quarter: None
As of February 10, 2022,9, 2023, Tucson Electric Power Company had 32,139,434 shares of common stock, no par value, outstanding, all of which were held by UNS Energy Corporation, an indirect wholly-owned subsidiary of Fortis Inc.
Documents incorporated by reference: None
Tucson Electric Power Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is, therefore, filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.
Explanatory Note
Tucson Electric Power (TEP) filed its Annual Report on Form 10-K for the fiscal year ended December 31, 2021 (Original Filing) with the U.S. Securities and Exchange Commission (SEC) on February 11, 2022. TEP is filing this Amendment No. 1 (Amendment) to the Original Filing solely for the purpose of filing revised versions of Exhibits 31(a), 31(b), and 32 submitted with the Original Filing (Exhibits). In the Original Filing, each of the Exhibits makes reference to the "quarterly report on Form 10-Q for the quarter ended December 31, 2021" rather than the "annual report on Form 10-K for the year ended December 31, 2021." The Exhibits have been modified in this Amendment solely to revise the references to the “annual report on Form 10-K for the year ended December 31, 2021” in each case and to reflect the date of filing of this Amendment. TEP has included in this Amendment a complete copy of the Original Filing, as amended per the above, and as modified to update the Exhibit Index included in Item 15 to indicate that Exhibit 23 and Exhibit 24 were filed with the Original Filing and are not being refiled as part of this Amendment.
No attempt has been made in this Amendment to amend, modify, or update any financial information or other disclosure presented in the Original Filing, nor does this Amendment reflect events occurring after the filing of the Original Filing or amend, modify, or update those disclosures, including the exhibits to the Original Filing and the Exhibit Index included in Item 15, except as described in the immediately preceding paragraph. Information described herein reflects the disclosures made at the time of the Original Filing on February 11, 2022. Accordingly, this Amendment should be read in conjunction with our filings made with the SEC subsequent to the filing of the Original Filing, including any amendments to those filings.
Table of Contents
DEFINITIONS
The abbreviations and acronyms used in the 20212022 Form 10-K are defined below:
INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS
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2015 Credit Agreement | | TEP's prior credit facility entered into in October 2015, and extended through October 2022, that provided for revolving credit commitments and a LOC facility |
20192022 Final FERC Rate CaseOrder | | In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedingsproceedings. In 2021, a settlement agreement was filed with the FERC. In 2022, the FERC approved the settlement agreement. |
| 2020 IRP | | TEP's 2020 Integrated Resource Plan filed with the ACC in June 2020, which outlines TEP'scalls for TEP to reduce its carbon emissions by 80% and to supply more than 70% of its energy portfolio throughto retail customers from renewable resources by 2035 |
| 2020 Rate Order | | A rate order issued by the ACC resulting in a new rate structure for TEP, effective on January 1, 2021 |
| 2021 Credit Agreement | | In OctoberThe 2021 TEP entered into an unsecured credit agreement thatCredit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits due inof $15 million and $50 million, respectively, and a maturity date of October 2026 |
| 2022 Rate Case | | In June 2022, TEP filed a general rate case with the termination dateACC based on a test year ended December 31, 2021 |
| ABR | | Alternate Base Rate |
| ACC | | Arizona Corporation Commission |
| ACC Refund Order | | An order issued by the ACC approving 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 a customer bill credit and a regulatory liability that reflects the deferral of the return of a portion of the savings, effective May 1, 2018 |
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| ADEQ | | Arizona Department of Environmental Quality |
| AFUDC | | Allowance for Funds Used During Construction |
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| AMT | | Alternative Minimum Tax |
| AOCI | | Accumulated Other Comprehensive Income |
| AOCL | | Accumulated Other Comprehensive Loss |
| ARO | | Asset Retirement Obligation |
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BTAASRFP | | Build-Transfer AgreementAll-Source Request for Proposals |
CARES Act | | Coronavirus Aid, Relief, and Economic Security Act |
| COVID-19 | | Coronavirus Disease 2019 |
| CCR | | Coal Combustion Residuals |
| CPP | | Clean Power Plan |
| DG | | Distributed Generation |
| DSM | | Demand Side Management |
| ECA | | Environmental Compliance Adjustor |
| EDIT | | Excess Deferred Income Taxes |
| EE Standards | | Energy Efficiency Standards |
| EIM | | Energy Imbalance Market |
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| EPA | | Environmental Protection Agency |
| FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
| GAAP | | Generally Accepted Accounting Principles in the United States of America |
| GHG | | Greenhouse Gas |
| ITC | | Investment Tax Credit |
| IRA | | Inflation Reduction Act signed into law on August 16, 2022 |
| IRS | | Internal Revenue Service |
| LFCR | | Lost Fixed Cost Recovery |
| LIBOR | | London Interbank Offered Rate |
| LOC | | Letter(s) of Credit |
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| NERC | | North American Electric Reliability Corporation |
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| NOPR | | Notice of Proposed Rulemaking |
| OATT | | Open Access Transmission Tariff |
| PBI | | Performance Based Incentives |
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| PPA | | Power Purchase Agreement |
| PPFAC | | Purchased Power and Fuel Adjustment Clause |
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| PSU | | Performance-Based Share Units |
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| PTC | | Production Tax Credit |
| PV | | Photovoltaic |
| RCRA | | Resource Conservation and Recovery Act |
| REC | | Renewable Energy Credit |
| Regional Haze | | Regional Haze Regulation promulgated by the EPA to improve visibility at national parks and wilderness areas |
| RES | | Renewable Energy Standard |
| REST | | Renewable Energy Standard and Tariff |
| Retail Rates | | Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment |
RICE | | Reciprocating Internal Combustion Engine |
| RMC | | Risk Management Committee |
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| RSU | | Restricted Share Units |
| RTM | | Resource Transition Mechanism |
| SERP | | Supplemental Executive Retirement Plan |
Summer MoratoriumSIP | | Emergency rules first enacted by the ACC in 2019 that suspend service disconnections and late fees for electric residential customers who otherwise would be eligible for service disconnection during the period from June 1 through October 15State Implementation Plan |
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| SOFR | | Secured Overnight Financing Rate |
| TCA | | Transmission Cost Adjustor |
| TCJA | | Tax Cuts and Jobs Act |
| TEAM | | Tax Expense Adjustor Mechanism |
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| VEBA | | Voluntary Employee Beneficiary Association |
| VIE | | Variable Interest Entity |
| WIIN | | Water Infrastructure Improvements for the Nation |
| WQARF | | Water Quality Assurance Revolving Fund |
ENTITIES AND GENERATING STATIONS
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| APS | | Arizona Public Service Company |
| Fortis | | Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4 |
| FortisUS | | Fortis intermediate holding company |
| Four Corners | | Four Corners Generating Station |
| Gila River | | Gila River Generating Station |
| Luna | | Luna Generating Station |
| Navajo | | Navajo Generating Station |
| Oso Grande | | A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico |
| PNM | | Public Service Company of New Mexico |
| San Juan | | San Juan Generating Station |
| SES | | Southwest Energy Solutions, Inc. |
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| Springerville | | Springerville Generating Station |
| Springerville Common Facilities | | Portion of the facilities at Springerville used in common with Springerville Unit 1 and Unit 2 |
| SRP | | Salt River Project Agricultural Improvement and Power District |
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| Sundt | | H. Wilson Sundt Generating Station |
| TEP | | Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation |
| Tri-State | | Tri-State Generation and Transmission Association, Inc. |
| UASTP | | University of Arizona Science and Technology Park |
| UNS Electric | | UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation |
| UNS Energy | | UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701 |
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| UNS Energy Affiliates | | Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc. |
| UNS Gas | | UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation |
UNITS OF MEASURE
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| AC | | Alternating Current |
| BBtu | | Billion British thermal unit(s) |
| GWh | | Gigawatt-hour(s) |
| kWh | | Kilowatt-hour(s) |
| kV | | Kilovolt |
| MMBtu | | Million Metric British thermal units |
| MW | | Megawatt(s) |
| MWh | | Megawatt-hour(s) |
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. TEP, or the Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany such forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as may otherwise be required by the federal securities laws.
Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed therein. We express our estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part I, Item 1A. Risk Factors; Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax, inclusive of the Inflation Reduction Act of 2022 and evolving interpretive guidance related thereto, and energy policies and the adoption of new regulations regarding electric service disconnections; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies and applications by other companies to the ACC requesting a certificate of public convenience and necessity to provide competitive electric generation service to customers in our service territory;policies; and/or changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output, or accelerate generation facility retirements; the final outcome of the 2019 FERC2022 Rate Case; the outcome of Phase 2 of the 2020 Rate Order; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usageusage; the continuation of customers;benefits of participation in the EIM; changes in energyelectricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality and/orand extreme weather events affecting electricity usage of our customers and/orand the performance of our operations; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the expected demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital and use the proceeds from any capital that we do raise as originally intended; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and related contribution requirements and expenses; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense;expense, including inflationary effects; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and DG initiatives; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other challengescyberspace attacks to our information security includingand our operations and technology systems;infrastructure, including attacks that may rise from heightened geopolitical instability; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; participation in the EIM; the extent of the impact of the COVID-19 pandemica global health crisis on our business and operations, and the economic and societal disruptions resulting therefrom and from the COVID-19 pandemic and government actions taken in response thereto; and the ongoing implementation of our 2020 IRP.
PART I
ITEM 1. BUSINESS
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson metropolitan area for 129130 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 438,000443,000 retail customers. TEP’s service territory covers 1,155 square miles and includes a population of over one million people in Pima County, as well as parts of Cochise County. TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP is subject to comprehensive state and federal regulation. The regulated electric utility operation is TEP's only segment.
TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis, whose principal executive offices are located in St. John's, Newfoundland and Labrador, Canada.
Regulated Utility Operations
TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for natural gas, coal-fired, and renewable 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
TEP has a forward-looking OATT formula rate, which updates annually and allows for timely recovery of transmission related costs. TEP's OATT formula rate is currently subjectcosts and an opportunity to refund following hearing and settlement procedures.earn a reasonable return on its investment. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
ACC Regulation and Rates
TEP operates under a certificate of public convenience and necessity as regulated by the ACC, under which TEP is obligated to provide electricity service to customers within its service territory. The ACC establishes rates that are designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates).investment.
The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission facilities,systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect TEP's business decisions and accounting practices.
Renewable Energy Standard
The ACC’s RES requires Arizona regulated utilities to 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 2021,2022, the percentage of retail kWh sales attributable to the RES was approximately 26%24%, exceeding the 20212022 requirement of 11%12%.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K 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. As of December 31, 2021,2022, TEP’s cumulative annual energy savings was approximately 23%24%.
1
RES requirements and EE 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.information regarding RES and EE Standards.
ACC Rates
Retail Rates are generally established in rate case proceedings. TEP's last rate case proceeding was finalized in 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 complycomplying 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 stationsfacilities to comply with environmental regulations.
•TEAM — a usage-based charge or credit that allows TEPused to pass-through the regulatory deferral balance related to the TCJA in 2021, the change in EDIT, and any materialpass through certain income tax effects to retail customers, which may include impacts of post-test year tax legislation.law changes.
•TCA — a usage-based charge or credit that allows TEP to reflect changes in costs related to investments and expenses included in TEP's FERC OATT formula rate.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations and Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on TEP's 20202022 Rate OrderCase 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) | (sales in GWh) | 2021 | | 2020 | | 2019 | | 2018 | | 2017 | (sales in GWh) | 2022 | | 2021 | | 2020 | | 2019 | | 2018 |
| Electric Sales | Electric Sales | | | | | | | | | | Electric Sales | | | | | | | | | |
| Residential | Residential | 3,820 | | 25 | % | | 4,170 | | | 28 | % | | 3,698 | | | 22 | % | | 3,766 | | | 24 | % | | 3,786 | | | 29 | % | Residential | 3,879 | | | 26 | % | | 3,820 | | | 25 | % | | 4,170 | | | 28 | % | | 3,698 | | | 22 | % | | 3,766 | | | 24 | % |
| Commercial | Commercial | 1,939 | | 13 | % | | 2,005 | | | 13 | % | | 2,077 | | | 13 | % | | 2,136 | | | 14 | % | | 2,192 | | | 17 | % | Commercial | 1,917 | | | 13 | % | | 1,939 | | | 13 | % | | 2,005 | | | 13 | % | | 2,077 | | | 13 | % | | 2,136 | | | 14 | % |
| Industrial, non-Mining | Industrial, non-Mining | 1,893 | | 12 | % | | 1,834 | | | 12 | % | | 1,896 | | | 11 | % | | 1,949 | | | 12 | % | | 1,939 | | | 15 | % | Industrial, non-Mining | 1,946 | | | 13 | % | | 1,893 | | | 12 | % | | 1,834 | | | 12 | % | | 1,896 | | | 11 | % | | 1,949 | | | 12 | % |
| Industrial, Mining | Industrial, Mining | 1,050 | | 7 | % | | 1,086 | | | 7 | % | | 1,057 | | | 6 | % | | 1,033 | | | 7 | % | | 991 | | | 8 | % | Industrial, Mining | 1,053 | | | 7 | % | | 1,050 | | | 7 | % | | 1,086 | | | 7 | % | | 1,057 | | | 6 | % | | 1,033 | | | 7 | % |
| | Other | Other | 16 | | — | % | | 16 | | | — | % | | 16 | | | — | % | | 16 | | | — | % | | 18 | | | — | % | Other | 15 | | | — | % | | 16 | | | — | % | | 16 | | | — | % | | 16 | | | — | % | | 16 | | | — | % |
| Total Retail Sales by Customer Class | 8,718 | | 57 | % | | 9,111 | | 61 | % | | 8,744 | | 53 | % | | 8,900 | | 57 | % | | 8,926 | | 68 | % | |
| Wholesale Sales, Long-Term | 837 | | 6 | % | | 508 | | | 4 | % | | 490 | | | 3 | % | | 424 | | | 3 | % | | 587 | | | 4 | % | |
Wholesale Sales, Short-Term(1) | 5,643 | | 37 | % | | 5,279 | | | 35 | % | | 7,257 | | | 44 | % | | 6,279 | | | 40 | % | | 3,630 | | | 28 | % | |
| Total Retail Sales | | Total Retail Sales | 8,810 | | 60 | % | | 8,718 | | 57 | % | | 9,111 | | 61 | % | | 8,744 | | 53 | % | | 8,900 | | 57 | % |
Wholesale, Long-Term (1) | | Wholesale, Long-Term (1) | 1,659 | | | 11 | % | | 837 | | | 6 | % | | 508 | | | 4 | % | | 490 | | | 3 | % | | 424 | | | 3 | % |
Wholesale, Short-Term (2) | | Wholesale, Short-Term (2) | 4,203 | | | 29 | % | | 5,643 | | | 37 | % | | 5,279 | | | 35 | % | | 7,257 | | | 44 | % | | 6,279 | | | 40 | % |
| Total Electric Sales | Total Electric Sales | 15,198 | | 100 | % | | 14,898 | | | 100 | % | | 16,491 | | | 100 | % | | 15,603 | | | 100 | % | | 13,143 | | | 100 | % | Total Electric Sales | 14,672 | | 100 | % | | 15,198 | | 100 | % | | 14,898 | | 100 | % | | 16,491 | | 100 | % | | 15,603 | | 100 | % |
| | Average Number of Retail Customers | Average Number of Retail Customers | | Average Number of Retail Customers | |
| Residential | Residential | 396,562 | | 90 | % | | 391,953 | | 90 | % | | 387,409 | | 90 | % | | 384,021 | | 90 | % | | 381,399 | | 90 | % | Residential | 400,751 | | 91 | % | | 396,562 | | 90 | % | | 391,953 | | 90 | % | | 387,409 | | 90 | % | | 384,021 | | 90 | % |
| Commercial | Commercial | 39,395 | | 9 | % | | 39,096 | | 9 | % | | 38,838 | | 9 | % | | 38,642 | | 9 | % | | 38,564 | | 9 | % | Commercial | 39,547 | | 9 | % | | 39,395 | | 9 | % | | 39,096 | | 9 | % | | 38,838 | | 9 | % | | 38,642 | | 9 | % |
| Industrial, non-Mining | Industrial, non-Mining | 523 | | — | % | | 491 | | — | % | | 503 | | — | % | | 504 | | — | % | | 520 | | — | % | Industrial, non-Mining | 574 | | — | % | | 523 | | — | % | | 491 | | — | % | | 503 | | — | % | | 504 | | — | % |
| Industrial, Mining | Industrial, Mining | 4 | | — | % | | 4 | | — | % | | 4 | | — | % | | 4 | | — | % | | 4 | | — | % | Industrial, Mining | 4 | | — | % | | 4 | | — | % | | 4 | | — | % | | 4 | | — | % | | 4 | | — | % |
| Other | Other | 1,873 | | 1 | % | | 1,877 | | 1 | % | | 1,872 | | 1 | % | | 1,873 | | 1 | % | | 1,879 | | 1 | % | Other | 1,875 | | — | % | | 1,873 | | 1 | % | | 1,877 | | 1 | % | | 1,872 | | 1 | % | | 1,873 | | 1 | % |
| Total Retail Customers | Total Retail Customers | 438,357 | | 100 | % | | 433,421 | | 100 | % | | 428,626 | | 100 | % | | 425,044 | | 100 | % | | 422,366 | | 100 | % | Total Retail Customers | 442,751 | | 100 | % | | 438,357 | | 100 | % | | 433,421 | | 100 | % | | 428,626 | | 100 | % | | 425,044 | | 100 | % |
(1)In 2020, short-termIncrease primarily due to an increase in sales decreasedto certain long-term wholesale customers.
(2)Decrease due to: (i)to the retirement of Navajo in 2019;coal-fired generation and (ii) Gila River Unit 2 replacing the generation to serve retail load. Short-term sales increasedload in 2019 and 2018 due to an increase in generation capacity related to Gila River Unit 2.2019.
Retail Customers
TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, healthcare, education, military bases, and governmental entities. TEP’s retail sales are influenced by several factors including economic conditions, seasonal weather patterns, DSM initiatives and the increasing use of energy-efficient products, and customer-sited DG.
Local, regional, and national economic factors impact the growth in the number of customers in TEP’s service territory. In each of the past five years, TEP’s average number of retail customers increased by approximately 1%. TEP expects the number of retail customers to increase at a rate of approximately 1% in 20222023 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 20212022 was 8,7188,810 GWh, which is a decrease of 2%1% from 20172018 levels. During the past five years, decreased sales volumes due to variation in weather and state requirements to promote energy efficiency and DG have been tempered by customer growth.
In 2020, due to changes in consumer and business behavior in response to the COVID-19 pandemic, there was a decrease in energy usage by commercial and industrial customers. Due to stay at homestay-at-home orders and the adoption of work from home practices, along with record heat in 2020, there was an offsetting increase in energy usage by residential customers starting in the second quarter of 2020. In 2021 and 2022, usage began to return to pre-COVID-19 pandemic patterns.
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 | | 20222023 |
| TRICO Electric Cooperative | | 2024 |
| Navopache Electric Cooperative | | 2041 |
Short-Term Wholesale Sales
Certain contracts for short-term wholesale sales cover periods of less than one year and obligate TEP to sell capacity or power at a fixed price. TEP also engages in short-term wholesale sales by selling power in the daily or hourly markets at fluctuating spot market prices and making other non-firm power sales. The majority of TEP's revenues from short-term wholesale sales are passed through to TEP’s retail customers offsetting fuel and purchased power costs. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices.
Energy Imbalance Market
In 2019, TEP signed an agreement with the California Independent System Operator indicating its intent to begin participating in the EIM.EIM, which TEP is preparing to enter the EIMsubsequently entered in the second quarter ofMay 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 continue to demonstrate resource adequacy through a combination of owned or contracted resources. TEP's participation in the EIM is expected to:EIM: (i) reduce thereduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allowallows for more effective integration of renewables; and (iii) enhanceenhances reliability through improved system utilization and responsiveness. These benefits are expected to be sustained over the life of TEP's participation in the EIM.
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 rulemaking dockets to evaluate possible modifications to various clean 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;competition; however, draft rules have not been officially proposed. In August 2021, a company filed an application with the ACC requesting a certificate of public convenience and necessity that would grant them the authority to provide competitive electric generation service to customers in TEP's service territory. In April 2022, legislation was signed into law that repealed statutes supporting statewide implementation of retail electric competition. The ACC has not yet determined whether to consider the application in light of this legislation. If the ACC chooses to consider this application, TEP would intervene in the matter and oppose the request. TEP cannot predict the outcome of this matter or its impact on TEP's financial position or results of operations.
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, 2021,2022, TEP had 3,1843,027 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 | | Unit | | Date | | | Capacity | | Operating | | TEP’s Share |
| Generation Source | Generation Source | | No. | | Location | | In Service | | | (MW) | | Agent | | % | | (MW) | Generation Source | | No. | | Location | | In Service | | | (MW) | | Agent | | % | | (MW) |
| Natural Gas | Natural Gas | | | | | | | | | | | | | | | | Natural Gas | | | | | | | | | | | | | | | |
| Gila River | Gila River | | 2 | | Gila Bend, AZ | | 2003 | | | 550 | | SRP | | 100 | | 550 | | Gila River | | 2 | | Gila Bend, AZ | | 2003 | | | 550 | | SRP | | 100 | | 550 | |
Gila River | Gila River | | 3 | | Gila Bend, AZ | | 2003 | | | 550 | | SRP | | 75.0 | | 413 | | Gila River | | 3 | | Gila Bend, AZ | | 2003 | | | 550 | | SRP | | 75.0 | | 413 | |
| Luna | Luna | | 1 | | Deming, NM | | 2006 | | | 555 | | PNM | | 33.3 | | 185 | | Luna | | 1 | | Deming, NM | | 2006 | | | 555 | | PNM | | 33.3 | | 185 | |
| Sundt | Sundt | | 3 | | Tucson, AZ | | 1962 | | | 104 | | TEP | | 100 | | 104 | | Sundt | | 3 | | Tucson, AZ | | 1962 | | | 104 | | TEP | | 100 | | 104 | |
| Sundt | Sundt | | 4 | | Tucson, AZ | | 1967 | | | 156 | | TEP | | 100 | | 156 | | Sundt | | 4 | | Tucson, AZ | | 1967 | | | 156 | | TEP | | 100 | | 156 | |
| Sundt Reciprocating Internal Combustion Engine | Sundt Reciprocating Internal Combustion Engine | | 1-10 | | Tucson, AZ | | 2019-2020 | | | 188 | | TEP | | 100 | | 188 | | Sundt Reciprocating Internal Combustion Engine | | 1-10 | | Tucson, AZ | | 2019-2020 | | | 188 | | TEP | | 100 | | 188 | |
| Sundt Internal Combustion Turbines | Sundt Internal Combustion Turbines | | Tucson, AZ | | 1972-1973 | | | 50 | | TEP | | 100 | | 50 | | Sundt Internal Combustion Turbines | | Tucson, AZ | | 1972-1973 | | | 50 | | TEP | | 100 | | 50 | |
DeMoss Petrie (1)(2) | DeMoss Petrie (1)(2) | | Tucson, AZ | | 2001 | | | 75 | | TEP | | 100 | | 75 | | DeMoss Petrie (1)(2) | | Tucson, AZ | | 2001 | | | 75 | | TEP | | 100 | | 75 | |
| North Loop | North Loop | | Tucson, AZ | | 2001 | | | 96 | | TEP | | 100 | | 96 | | North Loop | | Tucson, AZ | | 2001 | | | 96 | | TEP | | 100 | | 96 | |
| Coal | Coal | | | | Coal | | | |
| Springerville | Springerville | | 1 | | Springerville, AZ | | 1985 | | | 387 | | TEP | | 100 | | 387 | | Springerville | | 1 | | Springerville, AZ | | 1985 | | | 387 | | TEP | | 100 | | 387 | |
Springerville (2)(3) | Springerville (2)(3) | | 2 | | Springerville, AZ | | 1990 | | | 406 | | TEP | | 100 | | 406 | | Springerville (2)(3) | | 2 | | Springerville, AZ | | 1990 | | | 406 | | TEP | | 100 | | 406 | |
| San Juan | | 1 | | Farmington, NM | | 1976 | | | 340 | | PNM | | 50.0 | | 170 | | |
| Four Corners | Four Corners | | 4 | | Farmington, NM | | 1969 | | | 785 | | APS | | 7.0 | | 55 | | Four Corners | | 4 | | Farmington, NM | | 1969 | | | 785 | | APS | | 7.0 | | 55 | |
| Four Corners | Four Corners | | 5 | | Farmington, NM | | 1970 | | | 785 | | APS | | 7.0 | | 55 | | Four Corners | | 5 | | Farmington, NM | | 1970 | | | 785 | | APS | | 7.0 | | 55 | |
| Renewables | Renewables | | | | Renewables | | | |
Utility-Owned Renewables (3) | | Various | | 2002-2021 | | | 294 | | TEP | | 100 | | 294 | | |
| Total Capacity | | | | 3,184 | | |
| Utility-Owned Renewables | | Utility-Owned Renewables | | Various | | 2002-2022 | | | 307 | | TEP | | 100 | | 307 | |
Total Capacity (4) | | Total Capacity (4) | | | | 3,027 | |
| |
(1)In January 2023, Gila River Unit 3 turbine upgrades increased capacity by 10 MW for a total nominal capacity of 560 MW.
(2)DeMoss Petrie is accompanied by 10 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(2)(3)Springerville Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.
(3)(4)In May 2021, Oso GrandeJune 2022, San Juan Unit 1 was placedretired. TEP held a 50% ownership interest in service, adding 250 MWSan Juan Unit 1 with a total nominal capacity of wind-powered electric generation.170 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, compensatesand SRP, the owner of Springerville Unit 4, compensate TEP for operating the facilities andfacilities. Tri-State 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-Owned Renewables
As of December 31, 2021,2022, TEP owned 4457 MW of PV solar generation capacity and 250 MW of wind generation capacity, measured in AC. The following table presents TEP's owned renewable generation resources: | | Generation Source | Generation Source | | Location | | Date/Projected Date
in Service | | In Service
Capacity (MW) | | Under Development
Capacity (MW) | Generation Source | | Location | | Date/Projected Date
in Service | | In Service
Capacity (MW) | | Under Development
Capacity (MW) |
| Solar | Solar | | | | | | | | | Solar | | | | | | | | |
Fort Huachuca Phase I & II (1) | Fort Huachuca Phase I & II (1) | | Sierra Vista, AZ | | 2014-2017 | | 18 | | | Fort Huachuca Phase I & II (1) | | Sierra Vista, AZ | | 2014-2017 | | 18 | | |
Raptor Ridge (2) | | Raptor Ridge (2) | | Tucson, AZ | | 2022 | | 13 | | |
| Springerville Solar | Springerville Solar | | Springerville, AZ | | 2004-2014 | | 13 | | | Springerville Solar | | Springerville, AZ | | 2004-2014 | | 13 | | |
UASTP Phase I & II (2) | | Tucson, AZ | | 2010-2011 | | 6 | | | |
Solon Prairie Fire (2) | | Tucson, AZ | | 2012 | | 5 | | | |
| Residential Solar | | Tucson, AZ | | Various | | 2 | | | |
| Raptor Ridge | | Tucson, AZ | | 2022 | | 13 | | |
UASTP Phase I & II (3) | | UASTP Phase I & II (3) | | Tucson, AZ | | 2010-2011 | | 6 | | |
Solon Prairie Fire (3) | | Solon Prairie Fire (3) | | Tucson, AZ | | 2012 | | 5 | | |
| Small Solar Generation (<5MW) | | Small Solar Generation (<5MW) | | Tucson, AZ | | Various | | 2 | | | 3 | |
| | Wind | Wind | | Wind | |
Oso Grande (3) | | Chaves County, NM | | 2021 | | 250 | | | |
Oso Grande (4) | | Oso Grande (4) | | Chaves County, NM | | 2021 | | 250 | | |
| Total Capacity | Total Capacity | | 294 | | | 13 | | Total Capacity | | 307 | | | 3 | |
|
(1)TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.
(2)The Raptor Ridge was placed in service in June 2022.
(3)UASTP Phase I & II and Solon Prairie Fire are located on properties held under land easements and leases.
(3)(4)Oso Grande was placed in service in May 2021.is located on properties held under leases.
Renewable Power Purchase Agreements
As of December 31, 2021,2022, TEP had renewable PPAs for 256 MW from solar resources and 179 MW from wind resources as presented in the table below. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date. The following table's capacity is measured in AC: | | Generation Source | Generation Source | | Location | | Date/Projected Date
in Service | | | In Service
Capacity (MW) | | Under Development
Capacity (MW) | Generation Source | | Location | | Date/Projected Date
in Service | | | In Service
Capacity (MW) | | Under Development
Capacity (MW) |
| Solar | Solar | | | | | | | | | | Solar | | | | | | | | | |
Wilmot Solar (1) | Wilmot Solar (1) | | Sahuarita, AZ | | 2021 | | | 100 | | | Wilmot Solar (1) | | Sahuarita, AZ | | 2021 | | | 100 | | |
| Red Horse | Red Horse | | Willcox, AZ | | 2015 | | | 41 | | | Red Horse | | Willcox, AZ | | 2015 | | | 41 | | |
| Avalon I | Avalon I | | Sahuarita, AZ | | 2014 | | | 29 | | | Avalon I | | Sahuarita, AZ | | 2014 | | | 29 | | |
| Avra Valley | Avra Valley | | Marana, AZ | | 2012 | | | 25 | | | Avra Valley | | Marana, AZ | | 2012 | | | 25 | | |
| Picture Rocks | Picture Rocks | | Marana, AZ | | 2012 | | | 20 | | | Picture Rocks | | Marana, AZ | | 2012 | | | 20 | | |
| Avalon II | Avalon II | | Sahuarita, AZ | | 2016 | | | 16 | | | Avalon II | | Sahuarita, AZ | | 2016 | | | 16 | | |
| Valencia | Valencia | | Tucson, AZ | | 2013 | | | 10 | | | Valencia | | Tucson, AZ | | 2013 | | | 10 | | |
| E.On Tech Park | E.On Tech Park | | Tucson, AZ | | 2012 | | | 5 | | | E.On Tech Park | | Tucson, AZ | | 2012 | | | 5 | | |
| Gato Montes | Gato Montes | | Tucson, AZ | | 2012 | | | 5 | | | Gato Montes | | Tucson, AZ | | 2012 | | | 5 | | |
Small PPAs (<5MW) (2) | Small PPAs (<5MW) (2) | | Various | | Various | | | 5 | | | Small PPAs (<5MW) (2) | | Various | | Various | | | 5 | | |
Babacomari North | Babacomari North | | Cochise County, AZ | | 2022 | | | 80 | | Babacomari North | | Cochise County, AZ | | TBD | | | 80 | |
Babacomari South | Babacomari South | | Cochise County, AZ | | 2023 | | | 80 | | Babacomari South | | Cochise County, AZ | | TBD | | | 80 | |
| Wind | Wind | | | | Wind | | | |
Borderlands Wind (3) | Borderlands Wind (3) | | Catron County, NM | | 2021 | | | 99 | | | Borderlands Wind (3) | | Catron County, NM | | 2021 | | | 99 | | |
| Macho Springs | Macho Springs | | Deming, NM | | 2011 | | | 50 | | | Macho Springs | | Deming, NM | | 2011 | | | 50 | | |
| Red Horse Wind | Red Horse Wind | | Willcox, AZ | | 2015 | | | 30 | | | Red Horse Wind | | Willcox, AZ | | 2015 | | | 30 | | |
| Total Capacity | Total Capacity | | | | 435 | | | 160 | | Total Capacity | | | | 435 | | | 160 | |
(1)In April 2021, Wilmot Solar was placed in serviceis accompanied by 30 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(2)Iron Horse has 2 MW of capacity accompanied by 10 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(2)Iron Horse has 2 MW of capacity accompanied by 10 MW of battery storage. Payments for battery storage are accounted for as variable lease costs.
(3)Borderlands Wind was placed in service in December 2021.The commercial operation dates (CODs) were originally set for 2022 and 2023 for Babacomari North and South, respectively. The contracts were subsequently resubmitted through the ASRFP and, if selected, updated CODs will be finalized.
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 98 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.carry as a participant in the regional reserve-sharing organization.
Peak Demand and Future Resources
Peak Demand | | (in MW) | (in MW) | 2021 | | 2020 | | 2019 | | 2018 | | 2017 | (in MW) | 2022 | | 2021 | | 2020 | | 2019 | | 2018 |
| Retail Customers | Retail Customers | 2,427 | | | 2,467 | | | 2,367 | | | 2,413 | | | 2,415 | | Retail Customers | 2,273 | | | 2,427 | | | 2,467 | | | 2,367 | | | 2,413 | |
In 2021,2022, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale peak demand, while maintaining a reserve margin in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional entity with delegated authority from NERC.
Peak demand occurs during the summer months due to the cooling requirements of retail customers in TEP’s service territory. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. The decrease in retail peak demand in 2022 compared to the previous four years was primarily due to less extreme heat during peak load. Additionally, the impacts of remote work as a result of COVID-19 in 2021 and 2020 increased peak demand for residential customers in each of those years.
Forecasted retail peak demand for 20222023 is 2,2692,429 MW compared with actual peak demand of 2,4272,273 MW in 2021.2022. TEP’s 20222023 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 2022.2023.
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 through 2035 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 the Company's dependency on coal-fired generation over the next decade while developing new renewable energy projects like Oso Grande, Raptor Ridge, and energy storage projects to meet electric demand. OnIn February 9, 2022, the ACC acknowledged TEP’s IRP and found it to be reasonable and in the public interest.
In 2020, ACC staff issued a NOPR based on clean energy rules approved by the ACC. In June 2021, these rules were modified by amendments and sent back through the formal rulemaking process, resulting in ACC staff issuing a new NOPR in December 2021. The rules would have required affected utilities to, among other provisions, reduce carbon emissions below certain baseline levels, and would have also repealed the existing RES and EE Standards. In January 2022, the ACC rejected the new rules, effectively ending the rule-making process. Also in January 2022, the ACC voted to open a new rule-making docket on integrated resource planning. TEP cannot predict the timing or outcome
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, Purchased Power, and Other Resources
A summary of fuel, purchased power, and other resource information is provided below: | | | Average Cost (cents per kWh) | | Percentage of Total kWh Resources | | Average Cost (cents per kWh) | | Percentage of Total kWh Resources |
| | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Coal | Coal | 2.60 | | | 2.51 | | | 2.46 | | | 34 | % | | 37 | % | | 41 | % | Coal | 2.83 | | | 2.60 | | | 2.51 | | | 31 | % | | 34 | % | | 37 | % |
| Natural Gas | Natural Gas | 3.36 | | | 2.03 | | | 2.33 | | | 46 | % | | 49 | % | | 45 | % | Natural Gas | 5.36 | | | 3.36 | | | 2.03 | | | 42 | % | | 46 | % | | 49 | % |
| Purchased Power, Non-Renewable | Purchased Power, Non-Renewable | 8.88 | | | 6.26 | | | 4.09 | | | 10 | % | | 9 | % | | 10 | % | Purchased Power, Non-Renewable | 7.31 | | | 8.88 | | | 6.26 | | | 14 | % | | 10 | % | | 9 | % |
| Total Non-Renewable | Total Non-Renewable | | 90 | % | | 95 | % | | 96 | % | Total Non-Renewable | | 87 | % | | 90 | % | | 95 | % |
| | Purchased Power, Renewable | Purchased Power, Renewable | 7.63 | | | 9.42 | | | 9.43 | | | 6 | % | | 4 | % | | 4 | % | Purchased Power, Renewable | 6.76 | | | 7.63 | | | 9.42 | | | 8 | % | | 6 | % | | 4 | % |
| Utility-Owned, Renewable | Utility-Owned, Renewable | N/A | | N/A | | N/A | | 4 | % | | 1 | % | | — | % | Utility-Owned, Renewable | N/A | | N/A | | N/A | | 5 | % | | 4 | % | | 1 | % |
| Total Renewable | Total Renewable | | 10 | % | | 5 | % | | 4 | % | Total Renewable | | 13 | % | | 10 | % | | 5 | % |
| | Total Fuel, Purchased Power and Other Resources | Total Fuel, Purchased Power and Other Resources | | 100 | % | | 100 | % | | 100 | % | Total Fuel, Purchased Power and Other Resources | | 100 | % | | 100 | % | | 100 | % |
Coal Supply
The coal used for generation is low-sulfur, bituminous or sub-bituminous coal sourced from mines in Arizona and New Mexico. The table below provides information on the existing coal contracts that supply TEP's generation facilities. The average cost of coal per MMBtu, including transportation, was $2.65 in 2022, $2.48 in 2021, and $2.37 in 20202020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Station | | Coal Supplier | | 2022 Coal Consumption (tons in 000s) | | Contract Expiration Date | | Average Sulfur Content | | Coal Obtained From |
Springerville (1) | | Peabody CoalSales | | 1,993 | | 2031 | | 1.0% | | Lee Ranch Mine/El Segundo Mine |
| Four Corners | | NTEC | | 391 | | 2031 | | 0.7% | | Navajo Mine |
(1)In November 2022, TEP amended and 2019.extended its existing coal sales agreement for the supply of coal for Springerville Unit 1 through 2027 and Unit 2 through 2031. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Station | | Coal Supplier | | 2021 Coal Consumption (tons in 000s) | | Contract Expiration Date | | Average Sulfur Content | | Coal Obtained From |
| Springerville | | Peabody CoalSales | | 2,145 | | 2022 | | 1.0% | | Lee Ranch Mine/El Segundo Mine |
| Four Corners | | NTEC | | 306 | | 2031 | | 0.7% | | Navajo Mine |
| San Juan | | San Juan Coal Co. | | 578 | | 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' estimatedunits over their respective remaining life.
Coal-Fired Generation Facilities Operated by Others
TEP also participates in a jointly-owned coal-fired generation facilitiesfacility at Four Corners and San Juan.Corners. Four Corners, which is operated by APS, and San Juan, which is operated by PNM, area mine-mouth generation facilitiesfacility located adjacent to the coal reserves. TEP expects coal reserves available to these twothis jointly-owned generation facilitiesfacility to be sufficient for the remaining liveslife of the stations.station.
Natural Gas Supply
The table below provides information on the natural gas transportation agreements that deliver natural gas to TEP's generation facilities. The average cost of natural gas per MMBtu, including transportation, was $8.35 in 2022, $5.38 in 2021, and $2.19 in 2020,2020. The increase in cost in 2022 compared to 2021 was primarily due to an increase in natural gas prices resulting from increased demand and $2.20 in 2019.limited transportation capacity caused by constrained natural gas pipelines. The increase in cost in 2021 compared to 2020 and 2019 was primarily due to an increase in natural gas prices as a result of a severe winter storm in the southwestern United States in February 2021. | | | | | | | | | | | | | | | | |
| Station | | Natural Gas Transportation Counterparty | | | | Contract Expiration Date(s) |
| Gila | | Transwestern Pipeline Co./El Paso Natural Gas Company, LLC | | | | 2022-20402024-2040 |
| Luna | | El Paso Natural Gas Company, LLC | | | | 20222032 |
| Sundt | | El Paso Natural Gas Company, LLC | | | | 2023-2040 |
| DeMoss Petrie | | Southwest Gas Corporation | | | | Retail Tariff |
| North Loop | | Southwest Gas Corporation | | | | Retail Tariff |
Transmission and Distribution
TEP's distribution and transmission facilities are located in Arizona and New Mexico. These facilities are located on property owned by: (i) TEP; (ii) public entities; (iii) private entities; and (iv) Indian Nations. TEP's transmission and distribution systems included approximately 2,232 miles of transmission lines and 7,8547,910 miles of distribution lines as of December 31, 2021.2022.
TEP's transmission facilities transmit the output from TEP’s electric generation facilities to the Tucson area and power markets. The transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces, and parts of Mexico. TEP's transmission system, together with contractual rights on other systems, enables TEP to integrate and access generation resources to meet its energy load requirements.
ENVIRONMENTAL MATTERS
The EPA regulates, or has the authority to regulate, the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2), particulate matter, mercury, and other by-products produced by generation facilities. TEP may incur 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 98 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.
HUMAN CAPITAL
TEP strives to create a positive environment for its employees through its values and initiatives. As of December 31, 2021,2022, TEP had 1,7191,675 employees, of which approximately 794749 were represented by the International Brotherhood of Electrical Workers Local No. 1116 (IBEW).The current collective bargaining agreementsagreement between the IBEW and TEP expireexpired in July 2022, with wages in effect through December 2022. The IBEW and TEP extended the collective bargaining agreement through June 30, 2023, including a wage increase. Full negotiations are ongoing. TEP also engages with independent contractors in the ordinary course of its business, as necessary.
Governance and Culture
TEP strives to create a positive environment for its employees through various initiatives consistent with its values. The Company believes that the foundation for a diverse and inclusive work environment starts with the Executive Officers and Board of Directors' active involvement in tracking the Company's goals and objectives. TEP incorporates diversity, equity, and inclusion metrics and sustainability targets into its annual goals, which align these objectives with employee compensation. TEP's business strategy is intendedrepresents a commitment to help employees thrive through a commitment toby adapting to change, investing in continuous learning, and promoting collaboration, inclusion, and diversity, while deepening the Company's safety culture.
TEP's compliance team and Board of Directors review the Company's Code of Ethics and Business Conduct (Code) annually and make updates based on direct feedback from employees. The Code serves as TEP's ethical compass and expressly states that the Company will not tolerate certain behaviors including: (i) retaliation; (ii) discrimination; (iii) harassment; or (iv) abuse
of positions of trust for personal gain. The Code is intended to help TEP create a safe and respectful workplace where employees feel valued and secure.
Diversity, Equity, and Inclusion
Diversity, equity, and inclusion are an integral part of TEP’s vision and values. TEP values an inclusive culture and the unique contributions, perspectives, and experiences of its employees. 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. TEP incorporates diversity, equity, and inclusion metrics into its annual goals, and aligns these metrics with business objectives.
Business Resource Groups
The Company supports employee participation in Business Resource Groups (BRG), which are voluntary, employee-led groups that have established missions, goals, and practices that support career development and employee engagement and align with TEP's business priorities. Participants share ideas and issues to help promote an inclusive, equitable, and respectful workplace. Examples of BRGs that provide professional networking opportunities at TEP include:
•Veterans in Energy — dedicated to: (i) building relationships between its members; (ii) providing support and mentorship for military veterans and families; and (iii) promoting engagement and retention of military veteran employees.
•Women in Energy — dedicated to: (i) inspiring women in their professional growth; (ii) developing leadership qualities in women; and (iii) promoting engagement of women and diverse representation and thought.
Workforce Pipeline
TEP's workforce pipeline initiatives center on attracting, engaging, and developing a diverse workforce. Many of these efforts are specifically geared towards investing in: (i) students from historically underserved and minority students,backgrounds from elementary schools through post-graduate studies; (ii) individuals with disabilities; and (iii) military veterans.
TEP is a Troops to Energy Jobs employer that works with the Center for Energy Workforce Development to match military skills with open positions in a variety of fields within the Company. TEP has sponsored numerous military internships for separating or retiring service members in partnership with Davis-Monthan Air Force Base, among other military bases. As of December 31, 2021, 12%2022, 11% of TEP's employees were military veterans.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Executive Officers, who are elected annually by TEP’s Board of Directors, acting at the direction of the Board of Directors of UNS Energy, as of January 1, 2022,2023, are as follows: | | Name | Name | | Age | | Position(s) Held | | Executive Officer Since | Name | | Age | | Position(s) Held | | Executive Officer Since |
Susan M. Gray (1) | Susan M. Gray (1) | | 49 | | President and Chief Executive Officer | | 2015 | Susan M. Gray (1) | | 50 | | President and Chief Executive Officer | | 2015 |
Frank P. Marino (1) | Frank P. Marino (1) | | 57 | | Senior Vice President and Chief Financial Officer | | 2013 | Frank P. Marino (1) | | 58 | | Senior Vice President and Chief Financial Officer | | 2013 |
Todd C. Hixon (1) | Todd C. Hixon (1) | | 55 | | Senior Vice President, General Counsel and Corporate Secretary | | 2011 | Todd C. Hixon (1) | | 56 | | Senior Vice President, Chief Legal Officer, and Corporate Secretary | | 2011 |
| Erik B. Bakken | Erik B. Bakken | | 49 | | Vice President, System Operations and Energy Resources | | 2018 | Erik B. Bakken | | 50 | | Vice President of Energy Resources and Chief Sustainability Officer | | 2018 |
| Cynthia A. Garcia | | Cynthia A. Garcia | | 55 | | Vice President of Engineering and Safety and Chief Information Officer | | 2020 |
| J. Caleb Adcock | | J. Caleb Adcock | | 39 | | Vice President, Finance | | 2023 |
| Dallas J. Dukes | Dallas J. Dukes | | 54 | | Vice President, Customer Experience, Programs and Pricing | | 2019 | Dallas J. Dukes | | 55 | | Vice President, Customer Experience, Programs and Pricing | | 2019 |
| Cynthia A. Garcia | | 54 | | Vice President, Energy Delivery | | 2020 | |
| Orrin T. Nay | | Orrin T. Nay | | 58 | | Vice President of Field Operations | | 2022 |
| Christopher W. Norman | | Christopher W. Norman | | 47 | | Vice President, Public Policy and Corporate Strategy | | 2022 |
| Catherine E. Ries | Catherine E. Ries | | 62 | | Vice President of Talent | | 2007 | Catherine E. Ries | | 63 | | Vice President of Talent | | 2007 |
| Michael E. Sheehan | Michael E. Sheehan | | 54 | | Vice President of Strategic Planning and Energy Acquisition | | 2020 | Michael E. Sheehan | | 55 | | Vice President of Resource Planning, Fuels and Wholesale Marketing | | 2020 |
| Mary Jo Smith | | 64 | | Vice President and Policy Advisor | | 2015 | |
| Morgan C. Stoll | | 51 | | Vice President and Chief Information Officer | | 2016 | |
| Amy J. Welander | | Amy J. Welander | | 44 | | Vice President, General Counsel and Assistant Corporate Secretary | | 2023 |
| Gail M. Zody-Serbia | | Gail M. Zody-Serbia | | 45 | | Vice President of Human Resources | | 2022 |
| Martha B. Pritz | Martha B. Pritz | | 60 | | Treasurer | | 2017 | Martha B. Pritz | | 61 | | 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.
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.
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 andand/or reduce power consumption. These technologies includeconsumption, such as renewable energy resources, including energy storage and customer-sited DG, appliances, equipment, energy storage,energy-efficient products, and control systems. Continued development and use of these technologies and compliance with the ACC's EE Standards and RES continue to have a negative impact on TEP’s use per customer and overall retail sales. TEP's use per customer declined by an average of 1% per year from 20172018 through 2021.2022.
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. Unseasonably cool summers or warm winters may reduce customer usage, negatively affecting operating revenues, cash flows, and net income by reducing sales.
Production Tax Credits
Electricity generated from TEP's wind-powered facility depends heavily on wind conditions, turbine availability, and turbine availability.transmission capacity. If such conditions are unfavorable, the facility’s electricity generation and associated PTCs may be reduced, negatively affecting cash tax payments and net income.
TEP is dependent on a small number of customers for a significant portion of future revenues. A reduction in the electricity sales to these customers would negatively affect results of operations, net income, and cash flows at TEP.
TEP’s ten largest customers represented 10% of total revenues in 2021.2022. TEP sells electricity to mines, military installations, and other large commercial and industrial customers. Retail sales volumes and revenues from these customers could decline as a result of, among other things: global, national, and local economic conditions; curtailments of customer operations due to unfavorable market conditions; military base reorganization or closure decisions by the federal government; the effects of energy efficiency; or the decision by customers to self-generate all or a portion of their energy needs. A reduction in retail kWh sales by any one of TEP’s ten largest customers would negatively affect the Company's results of operations, net income, and cash flows.
REGULATORY
TEP's business is significantly impacted by government legislation, regulation and oversight. TEP's inability to recover its costs, earn a reasonable return on its investments, or comply with current regulations would negatively affect its results of operations, net income, and cash flows.
TEP's financial condition is influenced by how regulatory authorities, including the ACC and the FERC, establish the rates TEP can charge customers and authorize rates of return, common equity levels, and the amount of costs that may be recovered from TEP customers. The Company's ability to timely obtain rate adjustments that provide TEP with the opportunity to earn authorized rates of return depends upon timely regulatory action under applicable statutes and regulations and cannot be guaranteed.
•ACC—The ACC is a constitutionally created body composed of five elected commissioners and has jurisdiction over rates for retail customers. Commissioners are elected state-wide for staggered four-year terms and are limited to serving two consecutive terms. As a result, the composition of the ACC, and therefore its policies, are subject to change every two years.
•FERC—The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale.
Owners and operators of bulk power systems, including TEP, are subject to mandatory reliability standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new reliability standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory reliability standards could subject TEP to sanctions, including substantial monetary penalties.
Changes made to legislation, regulation, or regulatory structure could negatively affect TEP's results of operations, net income, and cash flows.
TEP incurs costs to comply with legislative and regulatory requirements and initiatives, such asincluding 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 initiativesInitiatives or changes to existing requirements have occurred and could arise again in the future through legislative, regulatory, or other initiatives (including ballot initiatives) on either a federal or state level.
TEP's ability to recover costs, including its investments, associated with legislative and regulatory initiatives will, in large part, depend on the final form of legislative or regulatory requirements. Further increases to rates could negatively affect the affordability of the rates charged to customers, which may negatively affect TEP’s results of operations, net income, and cash flows. flows. In 2019 and 2020,past years, the ACC staff has 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 outcomeresults of this matter.operations, net income, and cash flows.
ENVIRONMENTAL
TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it to environmental-related litigation and liabilities.
Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions of conventional pollutants and greenhouse gases,GHGs, water use, wastewater discharges, solid waste, hazardous waste, and management of CCR. Policy initiatives, such as environmental justice that considers disproportionately adverse environmental impacts on vulnerable communities, may also impact operations.
We have incurred costs in connection with environmental compliance, and we anticipate that we will continue to do so in the future. These laws and regulations can contribute to higher capital expenditures and operating expenses, particularly with regard toresulting from enforcement efforts focused on existing generation facilities and compliance standards related to new and existing generation facilities. These laws and regulations generally require TEP to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations.regulations and policies. Failure to comply with applicable laws and regulations, or address certain policies, may result in litigation, the imposition of fines, penalties, and requirements by regulatory authorities for costly equipment upgrades.
Existing environmental laws and regulations may be revised, and new environmental laws and regulations may be adopted or become applicable to the Company's facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a negative effect on TEP's results of operations, particularly if those costs are not timely and
fully recoverable from TEP customers. TEP’s obligation to comply with these laws and regulations as a participant or owner in regulated facilities like Springerville San Juan, and Four Corners, coupled with the financial impact of future climate change legislation, other environmental regulations and policies, and other business considerations, could jeopardize the economic viability of these generation facilities. Additionally, these regulations may jeopardize continued generation facility operations or the ability of
individual participants to meet their obligations and willingness to continue their participation in these facilities potentially resulting in an increased operational cost for the remaining participants.
TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generation facilities in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generation facilities. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.
FINANCIAL
Early closureAdditional early closures of TEP's coal-fired generation facilities could result in TEP recognizing regulatory impairments or increased cost of operations if recovery of TEP's remaining investments in such facilities and the costs associated with additional early closures are not permitted through rates charged to customers.
TEP's remaining coal-fired generation facilities may be closedclose before the end of their useful lives in response to economic conditions and/or changes in regulation, including any future changes to the ACC's energy rules and/or environmental regulations. If any of theadditional 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, 2021,2022, the net book value of TEP's in service coal-fired generation facilities was $1.1$1.0 billion.
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 and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flows from TEP's operations. Market disruptions such as those experienced in the financial crises of 2008, 2009, and 2020 in the United States and abroad may increase the Company's cost of borrowing or negatively affect TEP's ability to access sources of liquidity needed to finance the Company's operations and satisfy its obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties with which we do business, with,increases in interest rates in response to inflationary pressures, unprecedented volatility in the bank and capital markets, and general economic downturns in TEP's utility service territories.territory. If TEP is unable to access credit at reasonable rates, or if the Company's borrowing costs dramatically increase, TEP's ability to finance its operations, meet debt obligations, and execute its financial strategy could be negatively affected.
Increases in short-term interest rates would increase the cost of borrowings under TEP's credit facility.
In addition, changingunfavorable market conditions have and could continue to negatively affect the market value of assets held in its pension and other postretirement defined benefit plans and may increase the amount and accelerate the timing of required future funding contributions.
Generation facility closings or changesChanges in power flows intoin 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 a governmental authorities.authority. 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, 2021,2022, 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 on or after March 1, 2022.
In addition, as of December 31, 2021, there were outstanding approximately $107$91 million aggregate principal amount of tax-exempt bonds that financed local furnishing facilities, which include $16 million in bonds callable at par on or after June 1, 2022 and the balance callable at par on or after March 1, 2023. 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 was no longer tax-exempt.
any debt to refinance could be at a higher rate. 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, lower than expected levels of efficiency or operational performance, and/or disruptions in operations due to union strikes or a labor shortage. UnprecedentedGovernmental actions and other circumstances that cause continued global supply chain challenges including lead time impacts, pricingprice volatility, and other market trends, have and could continue to increase the risk that TEP’s operations could be negatively impacted and/or TEP’s capital spending could be increased. 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.increase. If TEP’s generation facilities or transmission and distribution systems operate below expectations, TEP’s operating results could be negatively affected and/or TEP's capital spending could be increased.
In addition, as coal-fired generation facilities are closed, the economic viability of coal mines and coal suppliers may be jeopardized. To date, several coal suppliers have declared bankruptcy and coal mines have been closed. As additional coal-fired generation facilities are closed, the availability of sufficient coal supplies could decrease and prices may increase, which could, in turn, negatively affect the viability of our remaining coal-fired generation facilities.
The operation of generation facilities and transmission systems on tribal lands may create operational and financial risks for TEP that, if realized, could negatively affect TEP’s results of operations, net income, and cash flows.
Certain jointly-owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements, or other rights-of-way that are effective for specified periods. TEP is unable to predict the final outcomes of pending and future approvals by the applicable sovereign governing bodies with respect to the cost of renewals and continued access to these leases, land easements, and rights-of-way. If pending and future approvals are not obtained and if continued access to the facilities is not granted, it could negatively affect TEP's results of operations, net income, and cash flows.
TEP receives power from certain generation facilities that are jointly-owned with, or operated by, third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could negatively affect TEP’s results of operations, net income, and cash flows.
Certain 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 impactimpacts regional and global weather conditions and resultresults in extreme weather events, including high temperatures, severe thunderstorms, drought, and wildfires. Changes in weather conditions orand extreme weather eventshave occurred in TEP’s service territory or affectingthe Western United States and have affected TEP's remote generation facilities or transmission and distribution systems maysystems. Such conditions could impact TEP's service territory, lead to service outages, andand/or cause business interruptions, which could result in an increase incause increased 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, thereThere can be no assurance that theyphysical utility assets will successfully do so in all circumstances.withstand severe weather conditions. In addition, changes in weather conditions or extreme weather events outside of TEP's service territory have and could again result in higher wholesale energy prices, insurance premiums and other costs, which couldcosts. These occurrences negatively impact TEP's business and operations. Any of these situations could haveoperations, leading to a negative impact on TEP's results of operations, net income, and cash flows.
TEP is subject to seasonal capacity shortfalls which could result in an inability to reliably serve load requirements and could negatively affect TEP’s results of operations, net income, and cash flows.
Increased capacity scarcity in the Western region may result in the inability to meet customer demand. Conditions that could cause a capacity shortfall include but are not limited to: an extreme weather event, regulatory policy, fuel supply shortages related to constrained natural gas pipelines or coal delivery interruptions, coal mine or natural gas well field outages, increased customer demand, unplanned outages, including extensions of planned outages due to equipment failures or other complications, and/or the retirement of generation resources. These conditions may contribute to market price volatility and
increased difficulty in procuring market energy. An inability to serve load requirements could negatively affect TEP’s results of operations, net income, and cash flows.
TEP is subject to physical attacks which could have a negative impact on the Company's business and results of operations.
TEP’s generation, transmission, and distribution facilitiesassets are critical to the provision of electric service to our customers, stability of the bulk electric system, and provide the framework for our service infrastructure. TEP is facing a heightened risk of physical attacks on the Company's electric systems.assets. The Company's electric generation, transmission, and distribution assets are geographically dispersed and are often in rural or unpopulated areas which makes it especially difficult to adequately detect, defend from, and respond to such
attacks. The Company relies on the continued operation of its network infrastructure,these assets, which isare part of an interconnected regional electrical grid. Any significant interruption of these assets could prevent the Company from fulfilling its critical business functions including delivering energy to customers. Security threats continue to evolve and adapt. Such attempts could be motivated by a desire to disrupt utility operations or seek financial gain. TEP, the energy industry, and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to disrupt operations.operations through physical security attacks and breaches. Such events or the threat of such events may increase costs associated with heightened security requirements. Despite implementation of security measures, there can be no assurance that the Company will be able to prevent the disruption of our operations.such disruptions.
If, despite TEP's security measures, a significant physical attack occurred, the Company could: (i) have operations disrupted, including a disruption to the stability of the bulk electric system, and/or property damaged; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations.
TEP is subject to cyber-attacks which could have a negative impact on the Company's business and results of operations.
Cybercrime, which includes the use of malware, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years. The Company experiences inherent technological risk due to hacking, viruses, acts of war or terrorism, and other types of data security breaches. The Company's utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. The Company relies on the continued operation of sophisticated digital information technology systems and network infrastructure which areto operate the utility as part of an interconnected regional electrical grid. TEP's operations technology systems face a heightened risk of cyber-attack due to the critical nature of 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.such infrastructure.
TEP's information technology systems and network infrastructure have been subject to, and will likely continue to be subject to, cyber-attacks from foreign or domestic sources attempting to gain unauthorized access to information and/or information systems 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'sSuch attempts could be motivated by a desire to disrupt utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.operations or seek financial gain.
If, despite TEP's security measures, a significant cybercybersecurity event or data breach occurred, the Company could: (i) have operations disrupted, have customer information stolen, and experience general business system and process interruption or compromise, including preventingthat which prevents TEP from servicing customers, collecting revenues or recording, processing and/or reporting financial information correctly; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations. 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 volatility and disruption of financial markets. Responses from governmental authorities and companies to reduce the spread of the COVID-19 pandemic have affected economic activity through various containment measures including, among others, business closures, work stoppages, quarantine and work-from-home guidelines, limiting capacity at public spaces and events, vaccination requirements, and/or restrictions of global and regional travel.
Due to the COVID-19 pandemic and these governmental authority and company responses, TEP could experience, and in some cases has experienced, among other things, workforce availability challenges, including from COVID-19 infections, quarantining, or concerns with vaccination or testing requirements, and the risks or uncertainties associated with plans for the return for many employees from remote to on-site work on a full-time or hybrid basis. 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, the continuation of workforce availability challenges, 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/or economic disruption, government-mandated actions in response to the COVID-19 pandemic, and labor shortages 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. The IRA was enacted on August 16, 2022. TEP is currently assessing the overall impacts of this legislation and interpretive guidance from tax authorities relating thereto. Legislative and/or regulatory changes have and could continue to impact our results of operations, net income, and cash flows.
The failure to attract, retain, and manage an appropriately qualified workforce could negatively impact TEP’s business and results of operations.
TEP’s business is dependent on its ability to attract, retain, and manage qualified personnel, including key executive officers and skilled professional and technical employees and contractors. Certain events and conditions, such as an aging workforce
without available replacements, a shift in employee expectations with respect to compensation and flexible work arrangements, the unavailability of contract resources, and the ongoing need to negotiate collective bargaining agreements with union employees, may lead to significant operating challenges, including lack of resources, loss of knowledge base, time required for skill development, and labor disruptions. If TEP is unable to successfully attract, retain, and manage an appropriately qualified workforce, its business and results of operations could be negatively affected.
The widespread outbreak of an illness, communicable disease, or any other public health crisis could adversely affect our business, results of operations and financial condition.
TEP could be negatively impacted by the widespread outbreak of an illness, 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 negatively impacted the economy on a global, national, and local level, disrupted global supply chains, and created volatility and disruption of financial markets. Responses from governmental authorities and companies to reduce the spread of the pandemic affected economic activity through various containment measures including, among others, business closures, work stoppages, quarantine and work-from-home guidelines, limiting capacity at public spaces and events, vaccination requirements, and/or restrictions of global and regional travel.
Another outbreak of an illness, a communicable disease, or any other public health crisis, and any resulting impacts, such as an extended period of global supply chain and/or economic disruption, labor shortages, or government-mandated actions in response to such public health crisis could materially affect TEP’s business, results of operations, access to sources of liquidity, and financial condition.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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 and renewal action by the applicable tribal or federal agencies are 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.
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 98 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
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.
ITEM 6. [Reserved]
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;
•current economic conditions;
•factors affecting results of operations;
•results of operations;
•liquidity and capital resources, including capital expenditures, income tax position, and 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 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 itemsactivity and year-to-year comparisons between 2021 and 2020. Discussions of 2019 activity and year-to-year comparisons between 2020 and 2019 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 20202021 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.Factors of this Form 10-K.
References in this discussion and analysis to "we" and "our" are to TEP.
OUTLOOK AND STRATEGIES
TEP'sOur financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws, regulations, and regulations;policies; and (iv) other regulatory and legislative actions. Our plans and strategies include:
•Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers.
•Continuing our transition from carbon-intensive sources to a more sustainable energy portfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. In 2020, we announced our long-termOur goal is to reduce carbon emissions by exiting coal-fired generation80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In May 2022, Fortis set a goal to achieve net-zero direct GHG emissions by 2050. The establishment of this additional target reinforces Fortis' commitment, along with that of its subsidiaries, to decarbonize over the next decadelong-term, while preserving customer reliability and increasing renewable energy resources and energy storage.affordability. These goals may be impacted by various federal and state energy policies, including policies currently under consideration.
•Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
CURRENT ECONOMIC CONDITIONS—COVID-19
The COVID-19 pandemic caused changes in consumer and business behavior and disrupted economic activity in TEP’s service territory. We activated our business continuity plans and we continue to evaluate and assess protocols and plans as pandemic conditions continue to evolve. Our protocols and plans are intended to support the continued delivery of safe and reliable service to our customers and the communities we serve.Performance - 2022 Compared with 2021
We cannot predict the ultimate effectsreported net income of the pandemic on the economy$217 million in 2022 compared with $201 million in 2021. The increase of $16 million, or our service territory. We continue8%, was primarily due to:
•$21 million in higher retail revenue primarily due to monitor developments affecting our workforce, customers, suppliers, and operations. We have not experienced a material impact to our results of operationshigher usage as a result of the COVID-19 pandemic.more favorable weather and increased LFCR revenue;
•$17 million in higher margin from wholesale transactions primarily due to an increase in sales volume; and
Performance - 2021 Compared with 2020
TEP reported net income of $201•$10 million in 2021 compared with $191 million in 2020. higher transmission related revenue impacted by favorable market conditions.
The increase of $10 million, or 5%, was primarily due to:partially offset by:
•$31 million in higher net revenue from an increase in rates as approved in the 2020 Rate Order; partially offset by unfavorable weather compared to 2020, which included record heat;
•$912 million in lower income tax expense primarilyAFUDC due to PTCs earneda decrease in eligible construction expenditures primarily as a result of Oso Grande being placed in service in May 2021;
•$811 million decrease in higher revenue duethe value of investments used to the 2019 FERC Rate Case proposed settlement triggering recognitionsupport certain post-employment benefits as a result of revenue previously reserved for refund, which included $6 million in transmission services provided in 2020 and 2019;unfavorable market conditions;
•$5 million increase in expected return on pension plan assets; and
•$56 million in higher wholesale long-term salesbase operations and maintenance expenses primarily due to an increase in sales volume.
The increase wasoutside services expense and employee wages expense; partially offset by:by lower remote plant expenses due to the shutdown of San Juan Unit 1 in June 2022; and
•$245 million in higher depreciation and amortization expense due to an increase in asset base; and an increase in depreciation rates and amortization as a result of the 2020 Rate Order;
•$21 million in higher operations and maintenance expenses due to an increase in planned generation outages in 2021 and employee wages and benefits expense; and
•$5 million in lower AFUDC due to a decrease in eligible construction expenditures as a result of Oso Grande being placed in service.base.
FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to the economic impacts of the COVID-19 pandemic, regulatory matters, generation resource strategy, 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 the pandemic. These developments are continuously evolving and are challenging to predict. Areas currently impacted, and areas we expect to continue to be impacted, that may have an effect on our results of operations, cash flows, and earnings are noted below.
Retail Sales
The COVID-19 pandemic changed consumer and business behavior as a result of safety measures taken to combat the spread. In 2020, energy usage by our commercial and industrial customers decreased below average levels experienced in prior periods and energy usage by our residential customers increased due to stay at home orders and widespread adoption of work from home practices. However, in 2021, usage began to return to pre-COVID-19 pandemic patterns. We have not experienced a significant impact on total retail sales as a result of the COVID-19 pandemic.
Regulatory Matters
We are subject to comprehensive regulation. The discussion below contains material developments toin those matters.
20202022 Rate OrderCase
In December 2020,June 2022, we filed a general rate case with the ACC issuedbased on a rate order for new rates that took effect January 1,test year ended December 31, 2021.
ProvisionsOur key 2022 Rate Case proposals are described below:
•a $136 million net increase in retail revenues comprised of the 2020 Rate Order include, but are not limited to:following components:
•◦a non-fuel retail revenue increase of $58$159 million over test year non-fuel retail revenues;
20◦a $66 million increase in fuel-related retail revenues, offset by a $71 million reduction in PPFAC revenues; and
Table of Contentschanges in certain adjustor mechanisms, including DSM, ECA, and RES, which result in an $18 million reduction in revenues.•a 7.04%7.31% return on original cost rate base of $2.7$3.6 billion, which includes a cost of equity of 9.15%10.25% and an average cost of debt of 4.65%3.82%; and
•a capital structure for rate making purposes of approximately 53%54% common equity and 47%46% long-term debt.debt; and
•a RTM adjustor that is designed to provide more timely recovery of our clean energy investments and replace the ECA.
We requested new rates to be implemented by September 1, 2023. We cannot predict the timing or outcome of this proceeding.
2020 ACC Phase 2 Proceedings
In addition,2020, the 2020 Rate OrderACC issued a rate order for new rates and established a second phase of our 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. In 2021, there was limited activity in this docket. On January 19, 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. We cannot predictIn January 2023, the timing or outcomeACC closed Phase 2 and ordered that just and equitable transition issues be considered as part of these proceedings.the 2022 Rate Case.
2019 FERC Rate CaseEnergy Imbalance Market
In 2019, we signed an agreement with the California Independent System Operator indicating our intent to begin participating in the EIM that we subsequently entered in May 2022. The EIM is a real-time energy market intended to resource low-cost energy to serve real-time consumer demand across a wide geographic area. Participation in the EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the EIM, we must continue to demonstrate
resource adequacy through a combination of owned or contracted resources. Our participation in the EIM: (i) reduces the costs to serve customers through a more efficient dispatch of a larger and more diverse pool of resources; (ii) allows for more effective integration of renewables; and (iii) enhances reliability through improved system utilization and responsiveness. These benefits are expected to be sustained over the life of our participation in the EIM.
2022 Final FERC Rate Order
In 2019, we filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a timely recovery of transmission-related costs. The FERC issued an order approving our proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the 2022 Final FERC Rate Order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.
Provisions of the ordersettlement agreement include, but are not limited to:
•replacing our stated transmission rates with a single forward-looking formula rate;
•a 10.4%9.79% 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.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. In February 2021, a Presiding Judge was appointed to continue the formula rate case proceeding after the settlement procedures resulted in an impasse. In August 2021, we filed an unopposed motion requesting that the Chief Judge suspend the litigation procedural schedule to allow the parties time to prepare and file a comprehensive settlement package, as parties in the proceeding reached a settlement in principle. The motion was granted and on December 22, 2021, the settlement agreement was filed with the FERC. On February 1, 2022, the Presiding Judge certified and recommended approval by the FERC of the proposed settlement.
Provisions of the proposed settlement include, but are not limited to:
•replacing our stated transmission rates with a single forward-looking formula rate;
•a 9.79% return on equity;
•elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor;
•a direct assignment of 25% of transmission costs allocated to retail customers and 75% allocated between wholesale and retail customers beginning January 1, 2022, through the date that is the later of: (i) December 31, 2031; or (ii) the date on which we have no Industrial Development Revenue Bonds outstanding; and
•a refund of the difference in rates for the period commencing August 1, 2019 through December 31, 2021.
The proposed settlement does not go into effect until final approval from the FERC is received. We cannot predict the final timing of the proceedings. AllIncreased rates charged under the revised OATT pursuant to the2022 Final FERC order areRate Order were subject to refund untiland deferred as a regulatory liability. In 2022, TEP returned all amounts in excess of the proceeding concludes. In December 2021, TEP recognized $12 million of wholesale revenue and had $15 million of wholesale revenues reservedrates approved in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheetssettlement agreement previously deferred as of December 31, 2021 and 2020.a regulatory liability. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the 2019 FERC Rate Case.information.
Other FERC Matters
In January 2021, the FERC notified us that it was commencing an audit with the intent 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 is coveringcovers the period fromof January 1, 2018, to December 31, 2021. On November 4, 2022, the present. TheFERC published without prejudice the final audit is ongoingreport with its findings and we cannot predictrecommendations. We accepted the outcome or findings if any,therein and submitted compliance items related to the audit in January 2023. We do not expect a material financial impact from the results of the FERC audit at this time.
Generation ResourcesResource Strategy
Our long-term strategy is to continue our shift from carbon-intensive sources to a more sustainable energy portfolio including expanding renewable energy resources while reducing reliance on coal-fired generation resources. In June 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.
In February 2022, the ACC acknowledged our 2020 IRP,
and found it to be reasonable and in the public interest. Our 2020 IRP includes a goal of reducingcalls for us to reduce our CO2carbon emissions by 80% comparedand to levels in 2005supply more than 70% of our energy to retail customers from renewable resources by 2035. To achieve this goal,In April 2022, we plan to continue the retirement of older fossil-fuel resourcesissued an ASRFP, which requests new wind and replace these assets with a combination of renewable resources,solar generation, energy storage systems, and other resources such as energy efficiency programs. Theresources. As part of the ASRFP, we received and are evaluating bids for all resource types.
Our existing coal-fired generation fleet faces a number of uncertainties impactingaffecting 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 ownedjointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we plan to exit all ownership interests in coal-fired generation facilities over the next decade. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions. On February 9, 2022, the ACC acknowledged TEP’s IRP and found it to be reasonable and in the public interest. The execution of our 2020 IRP is dependent on obtaining regulatory recovery approval in future separaterate proceedings. We filed the 2022 Rate Case with the ACC in June 2022.
Renewable Energy Projects
In 2021 threeand 2022, additional renewable energy projects were added to our resource portfolio increasing our total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 700 MW.
•In December 2021, a 99 MW wind facility achieved commercial operation. The PPA expires in 2051.
Oso Grande was placed in service, adding approximately 250 MW of wind-powered electric generation.
•In April 2021, a 100 MW solar facility, accompanied by 30 MW of battery storage, achieved commercial operation. The PPA expires in 2041.
We are planning to provide more than 70% of our power from renewable resources by 2035 as part of our transition to a cleaner energy portfolio. Oso Grande and the renewable PPAs provide a significant shift towards renewable generation and further decrease our dependency on coal-fired generation.
Arizona Energy Policy
In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various clean 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. In 2021, a company filed an application with the ACC requesting a certificate of public convenience and necessity that would grant them the authority to provide competitive electric generation service to customers in our service territory. If the ACC chooses to consider this application, we would intervene in the matter and oppose the request. We cannot predict the outcome of this matter or its impact on our financial position or results of operations.
In 2020, ACC staff issued a NOPR based on clean energy rules approved by the ACC. In June 2021, these rules were modified by amendments and sent back through the formal rulemaking process, resulting in ACC staff issuing a new NOPR in December 2021. The rules would have required us to, among other provisions, reduce carbon emissions below certain baseline levels. The new rules would also have repealed the existing RES and EE Standards, effective following the conclusion of our next rate case. In January 2022, the ACC rejected the new rules, effectively ending the rule-making process. Also in January 2022, the ACC voted to open a new rule-making docket on integrated resource planning. We cannot predict the timing or outcome of this proceeding.
Production Tax Credits
PTCs are per-kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In 2021, the PTC rate for electricity from wind was $0.025
per kWh generated. In May 2021, Oso Grande, a qualified energy resource, was placed in service.Oso Grande generated While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded approximately $19 million and $7 million in PTCs in 2021 and is expectedrelated to generate $25 million in PTCsOso Grande in 2022 at anticipated production.and 2021, respectively. The IRS published PTC rate for electricity produced by a qualified facility using wind was $0.026 for 2022 and $0.025 for 2021.
Contractual Provisions
If actual availability of the Oso Grande wind turbines is below a contractually established availability factor, we earn the rightare entitled to liquidated damages to partially offset the cost of operationincremental operations and maintenance costs incurred. We recognized a reductionrecorded reductions related to Oso Grande liquidated damages in Operations and Maintenance on the Consolidated Statements of Income of $2$3 million and $2 million in the yearyears ended December 31, 2022 and 2021, related to Oso Grande liquidated damages. Any liquidated damages in excess of operating expenses will reduce Utility Plant—Plant in Service on the Consolidated Balance Sheets.respectively. The PTCs and liquidated damages will mostly offset the operating expenses of Oso Grande, which is not currently reflected in base rates.
Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, the project’s electricity generation and associated PTCs may be substantially different than forecasted.
Arizona Energy Policy
In 2018, the ACC opened rulemaking dockets to evaluate integrated resource planning and retail competition for generation services. In 2019 and 2020, the ACC discussed draft rules related to retail electric competition, but such rules have not been officially proposed. In 2021, a company filed an application with the ACC requesting a certificate of public convenience and necessity that would grant it the authority to provide competitive electric generation service to customers in our service territory. In April 2022, legislation was signed into law that repealed statutes supporting statewide implementation of retail electric competition. The ACC has not yet determined whether to consider the application in light of this legislation.
Weather Patterns
Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year due to mild winter weather in our retail service territory. Seasonal fluctuations affect the comparability of our results of operations.
COVID-19 Pandemic Impact
The COVID-19 pandemic caused changes in consumer and business behavior and disrupted economic activity in our service territory. As the pandemic abates and conditions evolve, we continue to evaluate and assess protocols and plans and monitor our workforce, customers, suppliers, and operations. We have not experienced a material impact to our results of operations as a result of the COVID-19 pandemic.
Interest Rates
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this Form 10-K for information regarding interest rate risk and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of 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, REST, DSM, and TEAM are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on cost recovery mechanisms.
•Short-Term Wholesale Sales — Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC 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 20212022 compared to 20202021 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) | | Years Ended December 31, | | Increase (Decrease) | | Year Ended
December 31, | | Increase (Decrease) |
| (in millions) | (in millions) | 2021 | | 2020 | | Percent | | 2019 | | Percent | (in millions) | 2022 | | 2021 | | Percent | | 2020 | | Percent |
| Operating Revenues | Operating Revenues | | | | | | | | | | Operating Revenues | | | | | | | | | |
| Retail | Retail | $ | 1,088 | | | $ | 1,039 | | | 4.7 | % | | $ | 972 | | | 6.9 | % | Retail | $ | 1,140 | | | $ | 1,088 | | | 4.8 | % | | $ | 1,039 | | | 4.7 | % |
| Wholesale, Long-Term | Wholesale, Long-Term | 54 | | | 34 | | | 58.8 | % | | 34 | | | — | % | Wholesale, Long-Term | 99 | | | 54 | | | 83.3 | % | | 34 | | | 58.8 | % |
Wholesale, Short-Term (1) | Wholesale, Short-Term (1) | 238 | | | 151 | | | 57.6 | % | | 200 | | | (24.5) | % | Wholesale, Short-Term (1) | 330 | | | 238 | | | 38.7 | % | | 151 | | | 57.6 | % |
| Transmission | Transmission | 50 | | | 30 | | | 66.7 | % | | 32 | | | (6.3) | % | Transmission | 62 | | | 50 | | | 24.0 | % | | 30 | | | 66.7 | % |
| Springerville Units 3 and 4 Participant Billings | Springerville Units 3 and 4 Participant Billings | 95 | | | 78 | | | 21.8 | % | | 108 | | | (27.8) | % | Springerville Units 3 and 4 Participant Billings | 90 | | | 95 | | | (5.3) | % | | 78 | | | 21.8 | % |
| Other | Other | 68 | | | 93 | | | (26.9) | % | | 72 | | | 29.2 | % | Other | 87 | | | 68 | | | 27.9 | % | | 93 | | | (26.9) | % |
| Total Operating Revenues | Total Operating Revenues | $ | 1,593 | | | $ | 1,425 | | | 11.8 | % | | $ | 1,418 | | | 0.5 | % | Total Operating Revenues | $ | 1,808 | | | $ | 1,593 | | | 13.5 | % | | $ | 1,425 | | | 11.8 | % |
(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, other than those specifically associated with long-term contracts, are included in Wholesale, Short-Term in the table above.
TEP reported Operating Revenues of $1,808 million in 2022 compared with $1,593 million in 2021 compared with $1,425 million in 2020.2021. The increase of $168$215 million, or 12%13%, was primarily due to:
•$8492 million in higher short-term wholesale short-term sales primarily due to: (i)to an increase in price and salesprice; partially offset by a decrease in volume; and (ii) an increase in capacity sales to affiliates for a tolling PPA entered into in June 2021;
•$7052 million in higher retail revenue primarily due to: (i) an increase in rates as approved in the 2020 Rate Order; and (ii)to higher RESPPFAC cost recoveries as a result of a higher program expenses; partially offset by unfavorable weather comparedPPFAC rate and higher usage due to 2020 which included record heat;more favorable weather;
•$2045 million in higher transmission revenue primarily due to: (i) the 2019 FERC Rate Case proposed settlement triggering recognition of revenue previously reserved for refund; and (ii) an increase in transmission volumes;
•$20 million in higherlong-term wholesale long-term sales primarily due to an increase in sales volume;
•$19 million in higher participant billings related to Springerville Units 3 and 4; and
•$7 million in higher other revenue due to a natural gas transportation asset management agreement entered into in 2020.
The increase was partially offset by:
•$36 million in lower other revenue primarily due to decreasesan increase in: (i) LFCR revenues as a result of a rate adjustment as approved in the 2020 Rate Order; andadjustment; (ii) TCA revenues related to true-ups; and (iii) market prices related to our natural gas transportation asset management agreement; and
•$2112 million in lower retailhigher transmission related revenue primarily due to lower fuel and purchase power recoveries due to lower volumes and a lower average cost recovery rate.impacted by favorable market conditions.
The increase was partially offset by $5 million in lower participant billings related to Springerville Units 3 and 4 planned generation outages in 2021, not recurring in 2022.
The following table provides key statistics impacting Operating Revenues: | | | Years Ended December 31, | | Increase (Decrease) | | Year Ended
December 31, | | Increase (Decrease) | | Years Ended December 31, | | Increase (Decrease) | | Year Ended
December 31, | | Increase (Decrease) |
| (kWh in millions) | (kWh in millions) | 2021 | | 2020 | | Percent | | 2019 | | Percent | (kWh in millions) | 2022 | | 2021 | | Percent | | 2020 | | Percent |
Electric Sales (kWh) (1) | Electric Sales (kWh) (1) | | | | | | | | | | Electric Sales (kWh) (1) | | | | | | | | | |
| Retail Sales | Retail Sales | 8,718 | | | 9,111 | | | (4.3) | % | | 8,744 | | | 4.2 | % | Retail Sales | 8,810 | | | 8,718 | | | 1.1 | % | | 9,111 | | | (4.3) | % |
Wholesale, Long-Term (2) | Wholesale, Long-Term (2) | 837 | | | 508 | | | 64.8 | % | | 490 | | | 3.7 | % | Wholesale, Long-Term (2) | 1,659 | | | 837 | | | 98.2 | % | | 508 | | | 64.8 | % |
| Wholesale, Short-Term | Wholesale, Short-Term | 5,643 | | | 5,279 | | | 6.9 | % | | 7,257 | | | (27.3) | % | Wholesale, Short-Term | 4,203 | | | 5,643 | | | (25.5) | % | | 5,279 | | | 6.9 | % |
| Total Electric Sales | Total Electric Sales | 15,198 | | | 14,898 | | | 2.0 | % | | 16,491 | | | (9.7) | % | Total Electric Sales | 14,672 | | | 15,198 | | | (3.5) | % | | 14,898 | | | 2.0 | % |
| Average Revenue per kWh (3) | Average Revenue per kWh (3) | | Average Revenue per kWh (3) | |
| Retail | Retail | 12.48 | | | 11.40 | | | 9.5 | % | | 11.12 | | | 2.5 | % | Retail | 12.94 | | | 12.48 | | | 3.7 | % | | 11.40 | | | 9.5 | % |
| Wholesale, Long Term | Wholesale, Long Term | 6.46 | | | 6.76 | | | (4.4) | % | | 6.94 | | | (2.6) | % | Wholesale, Long Term | 5.99 | | | 6.46 | | | (7.3) | % | | 6.76 | | | (4.4) | % |
| Wholesale, Short-Term | Wholesale, Short-Term | 4.15 | | | 2.84 | | | 46.1 | % | | 2.87 | | | (1.0) | % | Wholesale, Short-Term | 7.62 | | | 4.15 | | | 83.6 | % | | 2.84 | | | 46.1 | % |
| Total Retail Customers (4) | Total Retail Customers (4) | 438,357 | | | 433,421 | | | 1.1 | % | | 428,626 | | | 1.1 | % | Total Retail Customers (4) | 442,751 | | | 438,357 | | | 1.0 | % | | 433,421 | | | 1.1 | % |
(1)These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.
(2)Increase in long-term wholesale sales volume is primarily due to an increase in sales to certain long-term wholesale customers.
(3)This metric represents the amount earned per kWh for retail and wholesale revenue. This number is calculated as revenue divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
(4)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 $771 million in 2022 compared with $606 million in 2021 compared with $515 million in 2020.2021. The increase of $91$165 million, or 18%27%, was primarily due to:
•$97105 million in higher fuel costs primarily due to: (i)to an increase in natural gas prices, net of realized gains on natural gas swaps, as a result of a severe winter storm in the southwestern United States in February 2021; and (ii) a tolling PPA entered into in June 2021;
•$57 million in higher purchased power primarily due to: (i) a tolling PPA entered into in June 2021; and (ii) an increase in price;prices; partially offset by a decrease in volume; andGas-Fired Generation volumes;
•$1337 million decrease in higher transmission costs primarily due to an increase in transmission purchases related to Oso Grande.
The increase was partially offset by $76 million of PPFAC eligible costs that were deferred as a regulatory asset for future recovery.recovery; and
•$19 million in higher transmission costs due to an increase in transmission purchases.
The following table provides key statistics impacting Fuel and Purchased Power: | | | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) | | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| (kWh in millions) | (kWh in millions) | 2021 | | 2020 | | Percent | | 2019 | | Percent | (kWh in millions) | 2022 | | 2021 | | Percent | | 2020 | | Percent |
| Sources of Energy | Sources of Energy | | | | | | | | | | Sources of Energy | | | | | | | | | |
| Coal-Fired Generation | Coal-Fired Generation | 5,309 | | | 5,778 | | | (8.1) | % | | 7,046 | | | (18.0) | % | Coal-Fired Generation | 4,626 | | | 5,309 | | | (12.9) | % | | 5,778 | | | (8.1) | % |
| Gas-Fired Generation | Gas-Fired Generation | 7,285 | | | 7,582 | | | (3.9) | % | | 7,714 | | | (1.7) | % | Gas-Fired Generation | 6,459 | | | 7,285 | | | (11.3) | % | | 7,582 | | | (3.9) | % |
Utility-Owned Renewable Generation (1) | Utility-Owned Renewable Generation (1) | 648 | | | 84 | | | * | | 75 | | | 12.0 | % | Utility-Owned Renewable Generation (1) | 816 | | | 648 | | | 25.9 | % | | 84 | | | * |
| Total Generation | Total Generation | 13,242 | | | 13,444 | | | (1.5) | % | | 14,835 | | | (9.4) | % | Total Generation | 11,901 | | | 13,242 | | | (10.1) | % | | 13,444 | | | (1.5) | % |
| Purchased Power, Non-Renewable | Purchased Power, Non-Renewable | 1,662 | | | 1,360 | | | 22.2 | % | | 1,709 | | | (20.4) | % | Purchased Power, Non-Renewable | 2,152 | | | 1,662 | | | 29.5 | % | | 1,360 | | | 22.2 | % |
Purchased Power, Renewable (2) | Purchased Power, Renewable (2) | 938 | | | 681 | | | 37.7 | % | | 643 | | | 5.9 | % | Purchased Power, Renewable (2) | 1,299 | | | 938 | | | 38.5 | % | | 681 | | | 37.7 | % |
Total Generation and Purchased Power (3) | Total Generation and Purchased Power (3) | 15,842 | | | 15,485 | | | 2.3 | % | | 17,187 | | | (9.9) | % | Total Generation and Purchased Power (3) | 15,352 | | | 15,842 | | | (3.1) | % | | 15,485 | | | 2.3 | % |
| | (cents per kWh) | (cents per kWh) | | (cents per kWh) | |
Average Fuel Cost of Generated Power (4) | Average Fuel Cost of Generated Power (4) | | Average Fuel Cost of Generated Power (4) | |
| Coal | Coal | 2.60 | | | 2.51 | | | 3.6 | % | | 2.46 | | | 2.0 | % | Coal | 2.83 | | | 2.60 | | | 8.8 | % | | 2.51 | | | 3.6 | % |
Natural Gas (5)(6) | Natural Gas (5)(6) | 3.36 | | | 2.03 | | | 65.5 | % | | 2.33 | | | (12.9) | % | Natural Gas (5)(6) | 5.36 | | | 3.36 | | | 59.5 | % | | 2.03 | | | 65.5 | % |
Average Cost of Purchased Power (7) | Average Cost of Purchased Power (7) | | Average Cost of Purchased Power (7) | |
Purchased Power, Non-Renewable (6) | Purchased Power, Non-Renewable (6) | 8.88 | | | 6.26 | | | 41.9 | % | | 4.09 | | | 53.1 | % | Purchased Power, Non-Renewable (6) | 7.31 | | | 8.88 | | | (17.7) | % | | 6.26 | | | 41.9 | % |
| Purchased Power, Renewable | Purchased Power, Renewable | 7.63 | | | 9.42 | | | (19.0) | % | | 9.43 | | | (0.1) | % | Purchased Power, Renewable | 6.76 | | | 7.63 | | | (11.4) | % | | 9.42 | | | (19.0) | % |
* Not meaningful
(1)In May 2021, Oso Grande was placed in service, adding 250 MW of wind-powered electric generation, increasing TEP's total utility-owned renewable generation.
(2)In April 2021, a 100 MW solar facility achieved commercial operation, adding up to 100 MW of renewable purchased power capacity for TEP under the related PPA.
(3)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.
(4)This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation stations.facilities.
(5)Includes realized gains and losses from hedging activity.
(6)In February 2021, a severe winter storm in the southwestern United States drove increased energy demand, limited the availability of natural gas to fuel generation stations,facilities, and increased the cost of natural gas and purchased power. In June 2021, the market price for purchased power increased significantly due to high demand resulting from higher than normal temperatures. In 2022, natural gas prices continued to increase due to extreme weather and limited transportation capacity caused by constrained natural gas pipelines.
(7)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 $405 million in 2022 compared with $397 million in 2021 compared with $352 million in 2020.2021. The increase of $45$8 million, or 13%, was primarily due to:
•$19 million in higher reimbursable maintenance expense at Springerville Units 3 and 4 primarily due to an increase in generation outages in 2021;
•$15 million in higher maintenance expense primarily due to an increase in generation outages in 2021; partially offset by lower bad debt expense; and
•$11 million in higher employee wages and benefits expense.
Depreciation and Amortization Expense
TEP reported Depreciation and Amortization total expense of $246 million in 2021 compared with $218 million in 2020. The increase of $28 million, or 13%2%, was primarily due to:
•$15 million in higher depreciationoutside services expense and amortization expense due to an increase in asset base;employee wages expense; and
•$133 million in higher depreciationREST and amortization expense due to an increase in depreciation rates and amortization as approved in the 2020 Rate Order.
Other Income (Expense)
TEP reported Other Income (Expense) expense of $49 million in 2021 and 2020. Changes in 2021 compared with 2020 were primarily due to:
•$6 million increase in other incomeDSM expenses primarily due to anhigher program expenses, including customer rebates.
The increase in expected return on pension plan assets; and
•$2 million increase in the value of investments used to support certain post-employment benefits as a result of favorable market conditions.
Offsetwas partially offset by:
•$8 million in lower operations expense related to the retirement of San Juan Unit 1 in June 2022; and
•$4 million in lower reimbursable maintenance expense related to Springerville Unit 4 planned outages in 2021, not recurring in 2022.
Depreciation and Amortization Expense
TEP reported Depreciation and Amortization expense of $251 million in 2022 compared with $246 million in 2021. The increase of $5 million, or 2%, was primarily due to an increase in asset base; partially offset by the retirement of San Juan Unit 1.
Other Income (Expense)
TEP reported Other Expense of $67 million in 2022 compared with $49 million in 2021. The increase of $18 million, or 37%, was primarily due to:
•$14 million in lower AFUDC primarily due to a decrease in eligible construction expenditures as a result of Oso Grande being placed in service in May 2021; and a 2020 FERC order that provided for an adjustment
•$11 million decrease in the AFUDC calculation not recurring in 2021.
Income Tax Expense
TEP reported Income Tax expensevalue of $32 million in 2021 compared with $41 million in 2020. The decreaseinvestments used to support certain post-employment benefits as a result of $9 million, or 22%, was primarily due to PTCs earned related to Oso Grande being placed in service in May 2021.unfavorable market conditions.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Any extended period of economic disruption could affect our business and financial conditions, and access to sources of liquidity. Cash flows 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 face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. We use our revolving credit as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.
Available Liquidity | | | | | |
| (in millions) | December 31, 20212022 |
| Cash and Cash Equivalents | $ | 1016 | |
Amount Available under Revolving Credit Agreement (1) | 225245 | |
| Total Liquidity | $ | 235261 | |
(1)The 20152021 Credit Agreement was amendedprovides for revolving credit commitments with swingline and restated inLOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2021, by the 2021 Credit Agreement.2026. See Access to Credit Agreement below.
Future Liquidity Requirements
We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflowsoutflows 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) contractedknown commitments and other contractual obligations including those forecasted in the Capital Expenditures tablebelow.capital expenditures.
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) | | Years Ended | | Increase
(Decrease) | | Year Ended | | Increase
(Decrease) |
| (in millions) | (in millions) | 2021 | | 2020 | | Percent | | 2019 | | Percent | (in millions) | 2022 | | 2021 | | Percent | | 2020 | | Percent |
| Operating Activities | Operating Activities | $ | 428 | | | $ | 466 | | | (8.2) | % | | $ | 414 | | | 12.6 | % | Operating Activities | $ | 509 | | | $ | 428 | | | 18.9 | % | | $ | 466 | | | (8.2) | % |
| Investing Activities | Investing Activities | (549) | | | (867) | | | (36.7) | % | | (654) | | | 32.6 | % | Investing Activities | (510) | | | (549) | | | (7.1) | % | | (867) | | | (36.7) | % |
| Financing Activities | Financing Activities | 72 | | | 455 | | | (84.2) | % | | 115 | | | 295.7 | % | Financing Activities | 19 | | | 72 | | | (73.6) | % | | 455 | | | (84.2) | % |
| Net Increase (Decrease) | Net Increase (Decrease) | (49) | | | 54 | | | * | | (125) | | | * | Net Increase (Decrease) | 18 | | | (49) | | | * | | 54 | | | * |
| Beginning of Period | Beginning of Period | 82 | | | 28 | | | 192.9 | % | | 153 | | | (81.7) | % | Beginning of Period | 33 | | | 82 | | | (59.8) | % | | 28 | | | 192.9 | % |
End of Period (1) | End of Period (1) | $ | 33 | | | $ | 82 | | | (59.8) | % | | $ | 28 | | | 192.9 | % | End of Period (1) | $ | 51 | | | $ | 33 | | | 54.5 | % | | $ | 82 | | | (59.8) | % |
* 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 decreasedincreased by $38$81 million in 20212022 compared with 20202021 primarily due to: (i) lower fuel and purchased power recoveries related to lower volumes and a lower average cost recovery rate; (ii) higher operations and maintenance expensesretail revenue primarily due to an increase in employee wages and benefits expense and planned generation outages in 2021; (iii) an increase in amounts returned to customers through bill credits related to the TCJA; and (iv) AMT credit refunds occurring in 2020higher PPFAC cost recoveries as a result of provisions of the CARES Act not recurring in 2021.
The decrease was partially offset by: (i)a higher retail revenues related to an increase in rates as approved in the 2020 Rate Order; (ii)PPFAC rate, higher gains from wholesale transactions; (iii) higher transmission revenue primarilysales due to a change in formula rates;more favorable weather, and (iv)increased LFCR revenue; (ii) changes in working capital related to higher sales and the timing of billing collections.collections and cash collateral deposits received from counterparties due to high natural gas forward prices; and (iii) higher margin from wholesale transactions primarily due to an increase in sales volumes.
The increase was partially offset by higher base operations and maintenance expenses primarily due to an increase in outside services expense and employee wages expense; partially offset by lower remote plant expenses due to the shutdown of San Juan Unit 1 in June 2022.
Investing Activities
Net cash flows used for investing activities decreased by $318$39 million in 20212022 compared with 20202021 primarily due to: (i) capital expenditures in 2020 of $285 million in payments for the Oso Grande project under the BTA and an $8 million payment for other investments not recurring in 2021; and (ii)to a decrease in cash used to purchase additional interestspaid for capital expenditures in generation facilities, net of proceeds received from the sale of an interest in a facility, not occurring in 2021.2022.
Financing Activities
Net cash flows provided by financing activities decreased by $383$53 million in 20212022 compared with 20202021 primarily due to: (i) lower proceeds from debt issuances and credit facility borrowings, net of repayments; and (ii) a decrease in equity contributions from UNS Energy. Energy; (ii) an increase in dividends declared and paid to UNS Energy; and (iii) lower proceeds from credit facility borrowings, net of repayments.
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, 2021,2022, TEP had no short-term investments.
Access to Credit Agreements
We have access to working capital through our credit agreement with lenders. In October 2021, TEP entered into an unsecured credit agreement that provides for revolving credit commitments plus swingline and LOC facilities, due in October 2026 (2021 Credit Agreement). The 2021 Credit Agreement has a capacity of $250 million with swingline and LOC sub-limits of $15 million and $50 million, respectively. The 2021 Credit Agreement amended and restated in its entirety the prior credit facility entered into in October 2015, and extended through October 2022, that provided for revolving credit commitments and an LOC facility (2015 Credit Agreement).
Amounts borrowed from the 2021 Credit Agreement will beare used for working capital and other general corporate purposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of
December 31, 2021,2022, there was $225$245 million available under the 2021 Credit Agreement. AsAgreement, which reflects no outstanding borrowings and a $5 million LOC issued with fees that accrue at a rate of February 10, 2022, there was $220 million available under the 2021 Credit Agreement.1.025% per annum.
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 agreement2021 Credit Agreement.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings. In December 2020, the ACC issued an order granting TEP financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate. In May 2022, we filed a Form S-3 with the SEC.
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 August 2021,June 2022, TEP redeemed at par $250prior to maturity $16 million aggregate principal amount of 5.15% senior unsecured notes prior to the maturityfixed rate tax-exempt bonds bearing interest at a rate of the notes.4.50% per annum.
•In May 2021,March 2022, TEP redeemed at par prior to maturity $177 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.
•In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2051,2032 with the proceeds used to redeem debt and for general corporate purposes.
We anticipate issuing long-term debt in the first quarter of 2022.2023, and plan to amend the 2021 Credit Agreement to provide for the transition to SOFR-based borrowings before the end of the second quarter of 2023.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2021,2022, 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 containThe 2021 Credit Agreement contains 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, 2021,2022, 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
TEP received no equity contributions from UNS Energy madein 2022 and received an equity contributions to TEPcontribution of $50 million in 2021 and $250 million in 2020.2021. 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 $63$100 million in dividends to UNS Energy in 20212022 and $75$63 million in 2020.2021.
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 established for TEP based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of December 31, 2021,2022, TEP had no cash posted as collateral to provide credit enhancement 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 particularly in view of heightened geopolitical instability and other potential impactsglobal supply chain challenges. In 2022, total capital expenditures of $458 million included: (i) investments in distribution and transmission assets including initial payments for the construction of the COVID-19 pandemicVail to Tortolita 230kV transmission line and ensure that we continue providing safea payment for a transmission right of way; and reliable service while supporting public health.(ii) final payments in the Raptor Ridge project. In 2021, total capital expenditures of $499 million included: (i) investments in distribution and transmission assets; and (ii) $10 million in payments for the Oso Grande project under the BTA. 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 the Oso Grande project under the BTA; and (iii) other investments in generation assets and an enhanced metering and distribution network.project.
Our forecasted capital expenditures presented below exclude amounts for AFUDC equity and other non-cash items: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | (in millions) | 2023 | | 2024 | | 2025 | | 2026 | | 2027 |
| Generation Facilities: | Generation Facilities: | | | | | | | | | | Generation Facilities: | | | | | | | | | |
Renewable Energy (1) | Renewable Energy (1) | $ | 9 | | | $ | 96 | | | $ | 223 | | | $ | 3 | | | $ | 76 | | Renewable Energy (1) | $ | 235 | | | $ | 41 | | | $ | 136 | | | $ | 298 | | | $ | 224 | |
| Other Generation Facilities | Other Generation Facilities | 56 | | | 48 | | | 34 | | | 63 | | | 44 | | Other Generation Facilities | 68 | | | 45 | | | 89 | | | 70 | | | 35 | |
| Total Generation Facilities | Total Generation Facilities | 65 | | | 144 | | | 257 | | | 66 | | | 120 | | Total Generation Facilities | 303 | | | 86 | | | 225 | | | 368 | | | 259 | |
Transmission and Distribution (2) | Transmission and Distribution (2) | 312 | | | 337 | | | 282 | | | 296 | | | 313 | | Transmission and Distribution (2) | 293 | | | 289 | | | 312 | | | 276 | | | 283 | |
General and Other (3) | General and Other (3) | 81 | | | 62 | | | 56 | | | 76 | | | 57 | | General and Other (3) | 85 | | | 69 | | | 80 | | | 71 | | | 66 | |
| Total Capital Expenditures | Total Capital Expenditures | $ | 458 | | | $ | 543 | | | $ | 595 | | | $ | 438 | | | $ | 490 | | Total Capital Expenditures | $ | 681 | | | $ | 444 | | | $ | 617 | | | $ | 715 | | | $ | 608 | |
(1)Includes investments in renewable energy includingand battery energy storage thatsystems, which we expect will allow us to continue our long-term strategy of shiftingtransitioning to a more diverse, sustainable energy portfolio.
(2)Increases due to investmentsInvestments in transmission capacity and distribution system reliability.
(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, including inflationary pressures, construction schedules, labor shortages and/or labor strikes, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, new or changing commitments, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt, other borrowings, or equity contributions.
Income Tax Position
Under the terms of the tax sharing agreement with UNS Energy, TEPwe received net refunds of $5 million in 2022 and made net payments of $7 million in 2021 and received net refunds of $10 million in 2020 and $14 million in 2019 related to federal income tax returns. Based on our remaining tax credit carryforward balances and limitations on their use in individual years, we expect to make tax sharing payments in 2022. Future payment obligations are subject to change and are not expected to have a significant impact on our operating cash flows.
Payroll TaxInflation Reduction Act
In responseOn August 16, 2022, President Biden signed the IRA into law. The IRA did not result in any immediate financial statement impacts for the Company. However, the legislation enacted a new corporate AMT of 15% that will be effective for tax years beginning after December 31, 2022. We expect to be subject to the COVID-19 pandemic, the CARES Act was signed into lawnew AMT based on March 27, 2020. As permitted by the CARES Act, TEP deferred paymentour status as a member 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 paid $3 million in December 2021 and expects to pay the remaining deferred deposits to the IRS in 2022.a foreign-parented multinational group.
Environmental Matters
The EPA regulates or has the authority to regulate the amount of SO2, NOx, CO2, particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. TEP will requestexpects recovery of the costs of environmental compliance through cost recovery mechanisms and Retail Rates. See Note 98 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 $2 million in 2022 and $3 million in 2021 in costs incurred to comply with environmental rules and regulations.
We capitalized $3 million in 2021 and $4 million in 2020 in costs incurred to comply with environmental rules and regulations. In addition, we recorded operations and maintenance expenses related to environmental compliance of $5$6 million in 2021, 2020,each of 2022 and 2019.2021. We expect environmental compliance related capital expenditures of $1$2 million in 2022each of 2023 and 2023, $2 million in 2024 and $1 million in each of 2025, 2026 and 2026.2027. 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),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 evaluation, commonly referred to as the four factor analysis, for both facilities. These evaluations were submitted to the ADEQ in March 2020 for the agency's use in developing the revised SIP. The regulatory deadline for ADEQ to submitsubmitted the revised SIP to the EPA for approval was July 31, 2021, however,in August 2022. The EPA issued a letter to the ADEQ was not ablefinding Arizona's SIP revision complies with the completeness criteria outlined in the rule. By statute, the EPA has one year from the completeness determination to meet this deadline, and is continuing to develop thetake action on Arizona's SIP for submittal.revision. Based on current Regional Haze requirement time-frames,timeframes, TEP anticipates that compliance strategies, if any, will likely be required to be implemented threetwo years after the ADEQ submitsADEQ's submission of the revised SIP to the EPA. TEP cannot predict the outcome of these matters at this time but will continue to work with the ADEQ to determine compliance strategies as needed.
Greenhouse Gas Regulation
In August 2015, the EPA issued the Clean Power Plan (CPP)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)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. Under the rule, theThe 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 March 5,In 2021, the U.S. Court of Appeals for the D.C. Circuit issued a mandate vacatingCircuit: (i) vacated the EPA's repeal of the CPP and remandingremanded it back to the EPA for further consideration (the vacatur was later stayed by the court); and (ii) vacated and remanded the ACE rule torule. Certain petitioners, defending the EPA.repeal of the CPP, filed petitions for an order requesting that the U.S. Supreme Court review the decision of the lower court. The mandate also vacated amendments that extended the timeline under which companies had to come into compliance with the rule. On October 29, 2021, the United StatesU.S. Supreme Court granted fourthe petitions, seeking reviewconsolidated the cases, and issued an opinion in June 2022 concerning the scope of the EPA's authority to regulate GHG emissions from existing coal-fired generation facilities under the Clean Air Act in June 2022. The U.S. Supreme Court reversed the D.C. Circuit's decisionCircuit and remanded the cases back for further proceedings consistent with the June 2022 opinion. In September 2022, the EPA announced the opening of a non-rulemaking docket for public comments on the EPA's efforts to vacate and remandreduce GHG emissions from existing fossil fuel-based generation facilities. Comments may be submitted to the ACE rule.EPA on or before March 27, 2023.
TEP cannot predict the 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 the 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. APS, the operating agent of Four Corners, began an assessment of corrective measures in 2019, and expectscompleted the assessment in 2022. The proposed final remedy was presented to continue into 2022.the public in August 2022, and a final remedy report is being prepared.
Since these regulations were finalized, the EPA has taken steps to further modify this rules.the rule. The following are pending rulemakings:
•In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN)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 thisthe WIIN 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.
•OnIn 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. TEP cannot predict the outcome or timing on when the EPA will take final action on this matter.
As of December 31, 2021,2022, the EPA has not taken final action on these proposals. As a result, TEP cannot predict the impactoutcome or timing of 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)ELGs 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. With the exception of Four Corners, none of TEP's coal-fired generation facilities are subject to the rule.
In response to legal challenges, the EPA revised the ELGs and issued a final rule on August 31, 2020, which became effective December 14, 2020. The final rule revised requirements for flue gas desulfurization wastewater and bottom ash transport water.
Withwater (BATW). To comply with the exception of Four Corners, none of TEP's coal-fired generation facilities are subjectrevised ELGs prior to the final rule. The revised ELGs warrantDecember 31, 2023, regulatory compliance date, APS will install and operate a modification ofBATW recycle system at Four Corners' wastewater discharge permit, orCorners. Additionally, APS filed a National Pollution Discharge Elimination System permit which was last issuedmodification request in January 2021. APS has been working with the EPA on the permit modification, including the establishment of compliance dates for the evaluation and testing of the BATW recycle system, and the establishment of interim discharge limits for operations between 2023 and 2025. TEP cannot predict the timing or final outcome of the permitting effort at this time. Our share of the cost to comply with the revised ELGs at Four Corners is estimated to be $3.3 million.
National Pollution Discharge Elimination System Permit
Several environmental non-governmental organizations (Petitioners) sought review of the EPA’s September 2019 issuance of Four Corners’ current National Pollution Discharge Elimination System permit from the EPA Environmental Appeals Board (EAB) in November 2019. The EAB denied the petition in September 2019.2020. In May 2022, the Petitioners, APS, and the operatorEPA executed a settlement agreement. The EPA has procured a contractor to conduct the surface water sampling program as outlined in the settlement agreement. The sampling program was finalized in December 2022. TEP cannot predict the timing or outcome of Four Corners, filed a permit modification request on January 11, 2021, which is still pending EPA final action. TEP doesthe surface water sampling program, but we do not anticipateexpect this matter to have a material impact on operations orour financial results.statements.
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 includedrecorded as an expense, or in AOCI, in the current period by unregulated companies. We evaluate regulatory assets and liabilities each period and believe future recovery or settlement is probable. Our assessment includes consideration of recent rate orders, historical regulatory treatment of similar costs, and changes in the regulatory and political environment. If management's assessment is ultimately different than actual regulatory outcomes, the impact on our results of operations, financial position, and future cash flows could be material.
As of December 31, 2021,2022, regulatory liabilities net of regulatory assets in the balance sheet totaled $79$118 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 reflectwill record our pension and other postretirement plan regulatory assets or liabilities in AOCIAOCL 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 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. Revenue is recorded 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, 2021. 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 estimated net removal costs. The ACC approves depreciation rates for all generation, distribution, and general plant assets. Depreciation rates for these assets cannot be changed without the ACC's approval. 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. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and amortized over the useful life of the related asset. Accretion of the liability and amortization of the asset are recorded as a regulated asset to be recovered through depreciation rates.
TEP identified legal obligations to retire generation facilities specified in land leases for its jointly-owned Four Corners, Navajo and San Juan facilities. 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 removingincurring costs to remove 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 $238$201 million at the retirement dates.Additionally, TEP entered into land lease agreements or land easement agreements with certain landowners for the installation of PV and wind assets. The provisions of the PV and wind land leases or land easements require TEP to remove the PV or wind facilities upon expiration of the agreements. In addition, TEP is required to properly dispose of or recycle certain PV assets under RCRA. We estimatedestimate our ARO related to the PV and wind assets to be approximately $52$50 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 $139$121 million as of December 31, 2021.2022. 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.current liability, noncurrent liability, or combination of both, and records the overfunded amount as a noncurrent asset. For plans other than the SERP, amounts not yet recognized in the income statement are recorded as a regulatory asset or liability to reflect expected recovery or refund of pension and other postretirement obligations or benefits through rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability and asset balances may vary significantly in future years. Key assumptions used include:
•discount rates used to determine obligations;
•expected returns on plan assets;
•compensation increases;
•mortality assumptions; and
•healthcare cost trend rates.
Discount Rates
As of December 31, 2021,2022, TEP discounted its future pension plan obligations at a rate of 3.2%5.7% and its other postretirement plan obligations at a rate of 3.0%5.6%. 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, 2021,2022, TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7.0%7.5%.
Compensation Increases
As of December 31, 2021,2022, TEP used a rate of compensation increase of 2.8%2.9% to measure pension obligations.
Mortality
TheThe 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, 20212022 and December 31, 2020.2021.
Healthcare Cost Trend Rates
TEP used a current year healthcare cost trend rate range between 5.5%6.0% and 6.5%7.0% in valuing its other postretirement benefit obligation as of December 31, 2021.2022. 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 basis100-basis point change to its assumptions as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Effect on Expense | | Effect on Obligation |
| (in millions) | Increase | | Decrease | | Increase | | Decrease |
| Change to Pension | | | | | | | |
| Discount Rate | $ | (8) | | | $ | 10 | | | $ | (85) | | | $ | 109 | |
| Long-Term Rate of Return on Plan Assets | (5) | | | 5 | | | N/A | | N/A |
| Change to Other Postretirement Benefits | | | | | | | |
| Discount Rate | (1) | | | 1 | | | (9) | | | 11 | |
| Long-Term Rate of Return on Plan Assets | — | | | — | | | N/A | | N/A |
| Healthcare Cost Trend Rate | 2 | | | (2) | | | 9 | | (8) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Effect on Expense | | Effect on Obligation |
| (in millions) | Increase | | Decrease | | Increase | | Decrease |
| Change to Pension | | | | | | | |
| Discount Rate | $ | (8) | | | $ | 11 | | | $ | (48) | | | $ | 60 | |
| Long-Term Rate of Return on Plan Assets | (5) | | | 5 | | | N/A | | N/A |
| Change to Other Postretirement Benefits | | | | | | | |
| Discount Rate | — | | | 1 | | | (7) | | | 8 | |
| Long-Term Rate of Return on Plan Assets | — | | | — | | | N/A | | N/A |
| Healthcare Cost Trend Rate | 2 | | | (1) | | | 7 | | (6) | |
In 2022,2023, TEP will incur pension costs of $7$10 million and other postretirement benefit costs of $5$6 million. TEP expects to record: (i) $20$13 million to operations and maintenance expense; and (ii) $6$3 million to capital; and (iii) $14 million to other income.capital. In 2022,2023, TEP expects to make pension plan contributions of $11$7 million and other retiree benefit payments of $5$6 million.
See Note 109 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension planplans 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, 2021,2022, 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP’s financial statements areTEP is exposed to certain market risks that can affect asset and liability fair value, results of operations, and cash flows. TEP's significant market risks are primarily associated with interest rates, commodity 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 Agreement
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under the 2021 Credit Agreement. The interest rate paid on borrowings is variable. Amounts borrowed under the credit agreement 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. TheTEP plans to amend the 2021 Credit Agreement providesto provide for transitionsthe transition to alternative benchmark rates.SOFR-based borrowings before the end of the second quarter of 2023.
The 2021 Credit Agreement provides for: (i) $250 million in revolving credit commitments; (ii) a $15 million swingline sublimit; and (iii) a $50 million LOC sublimit. The agreement matures in October 2026. As of December 31, 2021,2022, TEP had $15 million inno outstanding borrowings under the revolving credit facility and a $10$5 million LOC posted.
Commodity Price Risk
TEP is exposed to market fluctuations in electricity, natural gas, and coal prices as a result of its obligation to serve retail customer load in its regulated service territory and long-term wholesale contracts. Exposure to commodity prices consist primarily of variations in the price of fuel required to generate electricity that is purchased and sold in retail and wholesale markets. Commodity prices may be subject to significant price changes as supply and demand are impacted by, among otherunpredictable 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 commodity price risk using forwards, financial swaps, and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. We also mitigate exposure to commodity price risk with our ability to recover these costs in regulated rates through our PPFAC mechanism, which is subject to an annual review by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.
Certain commodity contracts qualify as derivatives and are recorded at fair value. The changes in fair value of such contracts have a high correlation to price changes in the hedged commodities. The following table shows the changes in fair value of our derivative positions: | | (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities | Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities | $ | 62 | | | $ | 21 | | | $ | (45) | | Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities | $ | 72 | | | $ | 62 | | | $ | 21 | |
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 | | Unrealized Gain (Loss) of TEP’s Hedging Activities |
| | Maturity 0 – 6 months | | Maturity 6 – 12 months | | Maturity over 1 yr. | | Total Unrealized Gain (Loss) | | Maturity 0 – 6 months | | Maturity 6 – 12 months | | Maturity over 1 yr. | | Total Unrealized Gain (Loss) |
| (in millions) | (in millions) | December 31, 2021 | (in millions) | December 31, 2022 |
| Prices Actively Quoted | Prices Actively Quoted | $ | (1) | | | $ | 4 | | | $ | 11 | | | $ | 14 | | Prices Actively Quoted | $ | 9 | | | $ | 5 | | | $ | 73 | | | $ | 87 | |
|
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 $7$1 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 $35$33 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. We mitigate risk by using long-term coal supply agreements with limited price movement. Our coal supply agreements expire from 2022 throughin 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 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 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, 2021,2022, our total credit exposure was approximately $40$122 million, and we had approximately $2$4 million of exposure to non-investment grade counterparties.
As of December 31, 2021,2022, we had no cash posted as collateral to provide credit enhancement. As of December 31, 2021,2022, we held approximately $2$15 million in collateral from our wholesale counterparties.
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, 20212022 and 2020,2021, the related consolidated statements of income, changes in stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2021,2022, 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, 20212022 and 2020,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021,2022, 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) relaterelates 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 relate.relates.
Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arizona Corporation Commission (the “ACC”) and Federal Energy Regulatory Commission (“FERC”). The ACC has jurisdiction with respect to the rates of electric distribution companies in Arizona. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. Management has determined it meets the requirements under accounting principles generally accepted in the United States of
America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; fuel expense; purchased power expense; operation and maintenance expense; and depreciation expense.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, (3) potential refunds to customers and (4) probability of potential charges related to the abandonment of regulated plants. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that
the regulatory authorities will not approve full recovery of the costs incurred. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the regulatory authorities included the following, among others:
•We evaluated the effectiveness of management’s controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory rate orders and settlements issued by the regulatory authorities for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the regulatory authorities’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the regulatory authorities and the filings with the regulatory authorities by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We inquired of management about 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 the board of directors and regulatory orders and other filings with the regulatory authorities to identify any evidence that may contradict management’s assertion regarding recoverability of such costs.
•We inspected regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. For significant projects that were over budget or if full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance of such costs.
| | |
| /s/ Deloitte & Touche LLP |
|
Phoenix,Tempe, Arizona |
February 10, 20229, 2023 |
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, | | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 | | 2022 | | 2021 | | 2020 |
| Operating Revenues | Operating Revenues | $ | 1,592,586 | | | $ | 1,424,741 | | | $ | 1,418,338 | | Operating Revenues | $ | 1,808,082 | | | $ | 1,592,586 | | | $ | 1,424,741 | |
| | Operating Expenses | Operating Expenses | | Operating Expenses | |
| Fuel | Fuel | 399,914 | | | 302,637 | | | 358,394 | | Fuel | 504,757 | | | 399,914 | | | 302,637 | |
| Purchased Power | Purchased Power | 204,264 | | | 146,968 | | | 137,977 | | Purchased Power | 209,790 | | | 204,264 | | | 146,968 | |
| Transmission and Other PPFAC Recoverable Costs | Transmission and Other PPFAC Recoverable Costs | 65,583 | | | 52,860 | | | 52,261 | | Transmission and Other PPFAC Recoverable Costs | 84,323 | | | 65,583 | | | 52,860 | |
| Increase (Decrease) to Reflect PPFAC Recovery Treatment | Increase (Decrease) to Reflect PPFAC Recovery Treatment | (64,155) | | | 12,565 | | | (42,836) | | Increase (Decrease) to Reflect PPFAC Recovery Treatment | (27,643) | | | (64,155) | | | 12,565 | |
| Total Fuel and Purchased Power | Total Fuel and Purchased Power | 605,606 | | | 515,030 | | | 505,796 | | Total Fuel and Purchased Power | 771,227 | | | 605,606 | | | 515,030 | |
| Operations and Maintenance | Operations and Maintenance | 397,095 | | | 351,584 | | | 377,563 | | Operations and Maintenance | 405,438 | | | 397,095 | | | 351,584 | |
| Depreciation | Depreciation | 201,524 | | | 189,051 | | | 169,042 | | Depreciation | 211,008 | | | 201,524 | | | 189,051 | |
| Amortization | Amortization | 43,995 | | | 28,754 | | | 27,706 | | Amortization | 40,045 | | | 43,995 | | | 28,754 | |
| Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | 62,010 | | | 58,222 | | | 55,642 | | Taxes Other Than Income Taxes | 63,706 | | | 62,010 | | | 58,222 | |
| Total Operating Expenses | Total Operating Expenses | 1,310,230 | | | 1,142,641 | | | 1,135,749 | | Total Operating Expenses | 1,491,424 | | | 1,310,230 | | | 1,142,641 | |
| | Operating Income | Operating Income | 282,356 | | | 282,100 | | | 282,589 | | Operating Income | 316,658 | | | 282,356 | | | 282,100 | |
| | Other Income (Expense) | Other Income (Expense) | | Other Income (Expense) | |
| Interest Expense | Interest Expense | (86,865) | | | (88,214) | | | (88,511) | | Interest Expense | (85,217) | | | (86,865) | | | (88,214) | |
| Allowance For Borrowed Funds | Allowance For Borrowed Funds | 6,624 | | | 9,480 | | | 5,744 | | Allowance For Borrowed Funds | 2,756 | | | 6,624 | | | 9,480 | |
| Allowance For Equity Funds | Allowance For Equity Funds | 17,885 | | | 22,847 | | | 15,222 | | Allowance For Equity Funds | 8,170 | | | 17,885 | | | 22,847 | |
| Unrealized Gains on Investments | 3,898 | | | 1,741 | | | 6,015 | | |
| Unrealized Gains (Losses) on Investments | | Unrealized Gains (Losses) on Investments | (7,094) | | | 3,898 | | | 1,741 | |
| Other, Net | Other, Net | 9,823 | | | 4,903 | | | (491) | | Other, Net | 14,414 | | | 9,823 | | | 4,903 | |
| Total Other Income (Expense) | Total Other Income (Expense) | (48,635) | | | (49,243) | | | (62,021) | | Total Other Income (Expense) | (66,971) | | | (48,635) | | | (49,243) | |
| | Income Before Income Tax Expense | Income Before Income Tax Expense | 233,721 | | | 232,857 | | | 220,568 | | Income Before Income Tax Expense | 249,687 | | | 233,721 | | | 232,857 | |
| Income Tax Expense | Income Tax Expense | 32,476 | | | 41,452 | | | 34,053 | | Income Tax Expense | 32,262 | | | 32,476 | | | 41,452 | |
| Net Income | Net Income | $ | 201,245 | | | $ | 191,405 | | | $ | 186,515 | | Net Income | $ | 217,425 | | | $ | 201,245 | | | $ | 191,405 | |
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, |
| 2022 | | 2021 | | 2020 |
| Cash Flows from Operating Activities | | | | | |
| Net Income | $ | 217,425 | | | $ | 201,245 | | | $ | 191,405 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | |
| Depreciation Expense | 211,008 | | | 201,524 | | | 189,051 | |
| Amortization Expense | 40,045 | | | 43,995 | | | 28,754 | |
| Amortization of Debt Issuance Costs | 3,000 | | | 2,829 | | | 2,721 | |
| Use of Renewable Energy Credits for Compliance | 44,762 | | | 45,815 | | | 44,517 | |
| Deferred Income Taxes | 32,825 | | | 37,217 | | | 39,408 | |
| Pension and Other Postretirement Benefits Expense | 12,207 | | | 15,342 | | | 14,883 | |
| Pension and Other Postretirement Benefits Funding | (17,818) | | | (20,806) | | | (21,018) | |
| | | | | |
| Allowance for Equity Funds Used During Construction | (8,170) | | | (17,885) | | | (22,847) | |
| | | | | |
| Regulatory Deferral, ACC Refund Order | — | | | — | | | (7,705) | |
| | | | | |
| Changes in Current Assets and Current Liabilities: | | | | | |
| Accounts Receivable | (120,780) | | | (18,738) | | | (19,019) | |
| Materials, Supplies, and Fuel Inventory | (12,953) | | | (18,445) | | | (3,460) | |
| Regulatory Assets | (76,900) | | | (59,542) | | | 5,339 | |
| Other Current Assets | (2,205) | | | 4,670 | | | (8,311) | |
| Accounts Payable and Accrued Charges | 132,796 | | | 14,979 | | | (20,885) | |
| Income Taxes Receivable/Payable | — | | | (3,271) | | | 10,245 | |
| | | | | |
| Regulatory Liabilities | (2,615) | | | (9,599) | | | 41,287 | |
| Other, Net | 56,783 | | | 8,724 | | | 1,689 | |
| Net Cash Flows—Operating Activities | 509,410 | | | 428,054 | | | 466,054 | |
| Cash Flows from Investing Activities | | | | | |
| Capital Expenditures | (457,517) | | | (499,405) | | | (839,958) | |
| Proceeds from Sale, Springerville Common Facilities | — | | | — | | | 29,569 | |
| | | | | |
| | | | | |
| Purchase Intangibles, Renewable Energy Credits | (63,738) | | | (55,297) | | | (53,509) | |
| | | | | |
| Other Investments | 2,517 | | | — | | | (8,500) | |
| Contributions in Aid of Construction | 8,131 | | | 5,678 | | | 4,615 | |
| | | | | |
| | | | | |
| | | | | |
| Net Cash Flows—Investing Activities | (510,607) | | | (549,024) | | | (867,783) | |
| Cash Flows from Financing Activities | | | | | |
| Proceeds from Borrowings, Revolving Credit Facility | 5,000 | | | 50,000 | | | 105,000 | |
| Repayments of Borrowings, Revolving Credit Facility | (20,000) | | | (35,000) | | | (105,000) | |
| Proceeds from Borrowings, Term Loan | — | | | — | | | 60,000 | |
| Repayments of Borrowings, Term Loan | — | | | — | | | (225,000) | |
Proceeds from Issuance, Long-Term Debt—Net of Discount | 323,804 | | | 322,231 | | | 645,768 | |
| Repayments of Long-Term Debt | (193,465) | | | (250,000) | | | (180,410) | |
| Dividends Paid to Parent | (100,000) | | | (62,500) | | | (75,000) | |
| Payments of Finance Lease Obligations | — | | | — | | | (17,087) | |
| Payment of Debt Issuance Costs | (3,012) | | | (4,382) | | | (6,327) | |
| Contributions from Parent | — | | | 50,000 | | | 250,000 | |
| Other, Net | 6,362 | | | 2,107 | | | 3,316 | |
| Net Cash Flows—Financing Activities | 18,689 | | | 72,456 | | | 455,260 | |
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 17,492 | | | (48,514) | | | 53,531 | |
| Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 33,489 | | | 82,003 | | | 28,472 | |
| Cash, Cash Equivalents, and Restricted Cash, End of Period | $ | 50,981 | | | $ | 33,489 | | | $ | 82,003 | |
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, |
| 2021 | | 2020 | | 2019 |
| Cash Flows from Operating Activities | | | | | |
| Net Income | $ | 201,245 | | | $ | 191,405 | | | $ | 186,515 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | |
| Depreciation Expense | 201,524 | | | 189,051 | | | 169,042 | |
| Amortization Expense | 43,995 | | | 28,754 | | | 27,706 | |
| Amortization of Debt Issuance Costs | 2,829 | | | 2,721 | | | 2,326 | |
| Use of Renewable Energy Credits for Compliance | 45,815 | | | 44,517 | | | 37,141 | |
| Deferred Income Taxes | 37,217 | | | 39,408 | | | 41,614 | |
| Pension and Other Postretirement Benefits Expense | 15,342 | | | 14,883 | | | 17,762 | |
| Pension and Other Postretirement Benefits Funding | (20,806) | | | (21,018) | | | (16,749) | |
| | | | | |
| Allowance for Equity Funds Used During Construction | (17,885) | | | (22,847) | | | (15,222) | |
| | | | | |
| Regulatory Deferral, ACC Refund Order | — | | | (7,705) | | | 7,705 | |
| Changes in Current Assets and Current Liabilities: | | | | | |
| Accounts Receivable | (18,738) | | | (19,019) | | | 9,238 | |
| Materials, Supplies, and Fuel Inventory | (18,445) | | | (3,460) | | | (16,236) | |
| Regulatory Assets | (59,542) | | | 5,339 | | | (20,934) | |
| Other Current Assets | 4,670 | | | (8,311) | | | (475) | |
| Accounts Payable and Accrued Charges | 14,979 | | | (20,885) | | | (27,776) | |
| Income Taxes Payable | (3,271) | | | 10,245 | | | 6,072 | |
| | | | | |
| Regulatory Liabilities | (9,599) | | | 41,287 | | | (1,626) | |
| Other, Net | 8,724 | | | 1,689 | | | 8,140 | |
| Net Cash Flows—Operating Activities | 428,054 | | | 466,054 | | | 414,243 | |
| Cash Flows from Investing Activities | | | | | |
| Capital Expenditures | (499,405) | | | (839,958) | | | (607,593) | |
| Proceeds from Sale, Springerville Common Facilities | — | | | 29,569 | | | — | |
| | | | | |
| | | | | |
| Purchase Intangibles, Renewable Energy Credits | (55,297) | | | (53,509) | | | (51,699) | |
| | | | | |
| Purchase, Other Investments | — | | | (8,500) | | | — | |
| Contributions in Aid of Construction | 5,678 | | | 4,615 | | | 6,607 | |
| Note Receivable | — | | | — | | | (1,000) | |
| | | | | |
| | | | | |
| Net Cash Flows—Investing Activities | (549,024) | | | (867,783) | | | (653,685) | |
| Cash Flows from Financing Activities | | | | | |
| Proceeds from Borrowings, Revolving Credit Facility | 50,000 | | | 105,000 | | | — | |
| Repayments of Borrowings, Revolving Credit Facility | (35,000) | | | (105,000) | | | — | |
| 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 | 322,231 | | | 645,768 | | | — | |
| Repayments of Long-Term Debt | (250,000) | | | (180,410) | | | (14,700) | |
| Dividends Paid to Parent | (62,500) | | | (75,000) | | | (75,000) | |
| Payments of Finance Lease Obligations | — | | | (17,087) | | | (10,890) | |
| Payment of Debt Issuance Costs | (4,382) | | | (6,327) | | | (757) | |
| Contributions from Parent | 50,000 | | | 250,000 | | | 50,000 | |
| Other | 2,107 | | | 3,316 | | | 1,514 | |
| Net Cash Flows—Financing Activities | 72,456 | | | 455,260 | | | 115,167 | |
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (48,514) | | | 53,531 | | | (124,275) | |
| Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 82,003 | | | 28,472 | | | 152,747 | |
| Cash, Cash Equivalents, and Restricted Cash, End of Period | $ | 33,489 | | | $ | 82,003 | | | $ | 28,472 | |
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, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Utility Plant | Utility Plant | | Utility Plant | |
| Plant in Service | Plant in Service | $ | 7,797,935 | | | $ | 7,073,292 | | Plant in Service | $ | 7,813,680 | | | $ | 7,797,935 | |
| | Construction Work in Progress | Construction Work in Progress | 320,931 | | | 627,382 | | Construction Work in Progress | 256,044 | | | 320,931 | |
| Total Utility Plant | Total Utility Plant | 8,118,866 | | | 7,700,674 | | Total Utility Plant | 8,069,724 | | | 8,118,866 | |
| Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | (2,786,839) | | | (2,645,333) | | Accumulated Depreciation and Amortization | (2,603,730) | | | (2,786,839) | |
| | Total Utility Plant, Net | Total Utility Plant, Net | 5,332,027 | | | 5,055,341 | | Total Utility Plant, Net | 5,465,994 | | | 5,332,027 | |
| | Investments and Other Property | Investments and Other Property | 81,958 | | | 76,299 | | Investments and Other Property | 74,128 | | | 81,958 | |
| | Current Assets | Current Assets | | Current Assets | |
| Cash and Cash Equivalents | Cash and Cash Equivalents | 9,970 | | | 60,960 | | Cash and Cash Equivalents | 16,237 | | | 9,970 | |
| Accounts Receivable (Net of Allowance for Credit Losses of $10,044 and $13,260) | 192,579 | | | 173,412 | | |
| Accounts Receivable (Net of Allowance for Credit Losses of $9,012 and $10,044) | | Accounts Receivable (Net of Allowance for Credit Losses of $9,012 and $10,044) | 320,899 | | | 192,579 | |
| Fuel Inventory | Fuel Inventory | 26,971 | | | 21,946 | | Fuel Inventory | 28,681 | | | 26,971 | |
| Materials and Supplies | Materials and Supplies | 141,677 | | | 126,788 | | Materials and Supplies | 155,650 | | | 141,677 | |
| Regulatory Assets | Regulatory Assets | 116,442 | | | 123,588 | | Regulatory Assets | 185,034 | | | 116,442 | |
| Derivative Instruments | Derivative Instruments | 19,406 | | | 16,094 | | Derivative Instruments | 27,019 | | | 19,406 | |
| Other | Other | 24,229 | | | 23,895 | | Other | 30,547 | | | 24,229 | |
| Total Current Assets | Total Current Assets | 531,274 | | | 546,683 | | Total Current Assets | 764,067 | | | 531,274 | |
| Regulatory and Other Assets | Regulatory and Other Assets | | | | Regulatory and Other Assets | | | |
| Regulatory Assets | Regulatory Assets | 267,669 | | | 318,474 | | Regulatory Assets | 184,894 | | | 267,669 | |
| Derivative Instruments | Derivative Instruments | 14,392 | | | 725 | | Derivative Instruments | 77,123 | | | 14,392 | |
| Other | Other | 94,420 | | | 92,605 | | Other | 123,575 | | | 94,420 | |
| Total Regulatory and Other Assets | Total Regulatory and Other Assets | 376,481 | | | 411,804 | | Total Regulatory and Other Assets | 385,592 | | | 376,481 | |
| Total Assets | Total Assets | $ | 6,321,740 | | | $ | 6,090,127 | | Total Assets | $ | 6,689,781 | | | $ | 6,321,740 | |
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, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| CAPITALIZATION AND OTHER LIABILITIES | CAPITALIZATION AND OTHER LIABILITIES | | | | CAPITALIZATION AND OTHER LIABILITIES | | | |
| Capitalization | Capitalization | | Capitalization | |
| Common Stock Equity: | Common Stock Equity: | | Common Stock Equity: | |
| Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2021 and 2020) | $ | 1,696,539 | | | $ | 1,646,539 | | |
| Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2022 and 2021) | | Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2022 and 2021) | $ | 1,696,539 | | | $ | 1,696,539 | |
| Capital Stock Expense | Capital Stock Expense | (6,357) | | | (6,357) | | Capital Stock Expense | (6,357) | | | (6,357) | |
| Retained Earnings | Retained Earnings | 850,942 | | | 712,197 | | Retained Earnings | 968,367 | | | 850,942 | |
| Accumulated Other Comprehensive Loss | Accumulated Other Comprehensive Loss | (9,915) | | | (10,942) | | Accumulated Other Comprehensive Loss | (2,884) | | | (9,915) | |
| Total Common Stock Equity | Total Common Stock Equity | 2,531,209 | | | 2,341,437 | | Total Common Stock Equity | 2,655,665 | | | 2,531,209 | |
| Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2021 and 2020) | — | | | — | | |
| Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2022 and 2021) | | Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2022 and 2021) | — | | | — | |
| | Long-Term Debt, Net | Long-Term Debt, Net | 2,134,534 | | | 1,814,059 | | Long-Term Debt, Net | 2,114,980 | | | 2,134,534 | |
| Total Capitalization | Total Capitalization | 4,665,743 | | | 4,155,496 | | Total Capitalization | 4,770,645 | | | 4,665,743 | |
| Current Liabilities | Current Liabilities | | | | Current Liabilities | | | |
| Current Maturities of Long-Term Debt, Net | Current Maturities of Long-Term Debt, Net | — | | | 249,752 | | Current Maturities of Long-Term Debt, Net | 149,957 | | | — | |
| Borrowings Under Credit Agreement | Borrowings Under Credit Agreement | 15,000 | | | — | | Borrowings Under Credit Agreement | — | | | 15,000 | |
| | Accounts Payable | Accounts Payable | 139,329 | | | 109,461 | | Accounts Payable | 233,920 | | | 139,329 | |
| Accrued Taxes Other than Income Taxes | Accrued Taxes Other than Income Taxes | 53,534 | | | 50,278 | | Accrued Taxes Other than Income Taxes | 58,914 | | | 53,534 | |
| Accrued Employee Expenses | Accrued Employee Expenses | 36,217 | | | 35,129 | | Accrued Employee Expenses | 38,459 | | | 36,217 | |
| Accrued Interest | Accrued Interest | 16,265 | | | 16,337 | | Accrued Interest | 14,868 | | | 16,265 | |
| Regulatory Liabilities | Regulatory Liabilities | 111,356 | | | 151,189 | | Regulatory Liabilities | 110,782 | | | 111,356 | |
| Customer Deposits | Customer Deposits | 12,791 | | | 16,450 | | Customer Deposits | 14,073 | | | 12,791 | |
| Derivative Instruments | Derivative Instruments | 15,854 | | | 27,789 | | Derivative Instruments | 12,752 | | | 15,854 | |
| Other | Other | 25,358 | | | 22,031 | | Other | 49,163 | | | 25,358 | |
| Total Current Liabilities | Total Current Liabilities | 425,704 | | | 678,416 | | Total Current Liabilities | 682,888 | | | 425,704 | |
| Regulatory and Other Liabilities | Regulatory and Other Liabilities | | | | Regulatory and Other Liabilities | | | |
| Deferred Income Taxes, Net | Deferred Income Taxes, Net | 548,750 | | | 492,919 | | Deferred Income Taxes, Net | 590,926 | | | 548,750 | |
| Regulatory Liabilities | Regulatory Liabilities | 352,226 | | | 390,164 | | Regulatory Liabilities | 377,546 | | | 352,226 | |
| Pension and Other Postretirement Benefits | Pension and Other Postretirement Benefits | 120,020 | | | 163,652 | | Pension and Other Postretirement Benefits | 69,048 | | | 120,020 | |
| Derivative Instruments | Derivative Instruments | 3,848 | | | 37,958 | | Derivative Instruments | 4,787 | | | 3,848 | |
| Other | Other | 205,449 | | | 171,522 | | Other | 193,941 | | | 205,449 | |
| Total Regulatory and Other Liabilities | Total Regulatory and Other Liabilities | 1,230,293 | | | 1,256,215 | | Total Regulatory and Other Liabilities | 1,236,248 | | | 1,230,293 | |
| | Commitments and Contingencies | Commitments and Contingencies | 0 | | 0 | Commitments and Contingencies | |
| | Total Capitalization and Other Liabilities | Total Capitalization and Other Liabilities | $ | 6,321,740 | | | $ | 6,090,127 | | Total Capitalization and Other Liabilities | $ | 6,689,781 | | | $ | 6,321,740 | |
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, 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 | | |
| | | | Common Stock | | Capital Stock Expense | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Stockholder's Equity |
| Balances as of December 31, 2019 | Balances as of December 31, 2019 | $ | 1,396,539 | | | $ | (6,357) | | | $ | 595,792 | | | $ | (7,771) | | | $ | 1,978,203 | | Balances as of December 31, 2019 | $ | 1,396,539 | | | $ | (6,357) | | | $ | 595,792 | | | $ | (7,771) | | | $ | 1,978,203 | |
| Net Income | Net Income | | 191,405 | | | 191,405 | | Net Income | | 191,405 | | | 191,405 | |
| Other Comprehensive Loss, Net of Tax | | (3,171) | | | (3,171) | | |
| Other Comprehensive Income(Loss), Net of Tax | | Other Comprehensive Income(Loss), Net of Tax | | (3,171) | | | (3,171) | |
| Dividends Declared to Parent | Dividends Declared to Parent | | (75,000) | | | (75,000) | | Dividends Declared to Parent | | (75,000) | | | (75,000) | |
| Contribution from Parent | Contribution from Parent | 250,000 | | | 250,000 | | Contribution from Parent | 250,000 | | | 250,000 | |
| | Balances as of December 31, 2020 | Balances as of December 31, 2020 | $ | 1,646,539 | | | $ | (6,357) | | | $ | 712,197 | | | $ | (10,942) | | | $ | 2,341,437 | | Balances as of December 31, 2020 | $ | 1,646,539 | | | $ | (6,357) | | | $ | 712,197 | | | $ | (10,942) | | | $ | 2,341,437 | |
| Net Income | Net Income | | 201,245 | | | 201,245 | | Net Income | | 201,245 | | | 201,245 | |
| Other Comprehensive Income, Net of Tax | | 1,027 | | | 1,027 | | |
| Other Comprehensive Income(Loss), Net of Tax | | Other Comprehensive Income(Loss), Net of Tax | | 1,027 | | | 1,027 | |
| Dividends Declared to Parent | Dividends Declared to Parent | | (62,500) | | | (62,500) | | Dividends Declared to Parent | | (62,500) | | | (62,500) | |
| Contribution from Parent | Contribution from Parent | 50,000 | | | 50,000 | | Contribution from Parent | 50,000 | | | 50,000 | |
| | Balances as of December 31, 2021 | Balances as of December 31, 2021 | $ | 1,696,539 | | | $ | (6,357) | | | $ | 850,942 | | | $ | (9,915) | | | $ | 2,531,209 | | Balances as of December 31, 2021 | $ | 1,696,539 | | | $ | (6,357) | | | $ | 850,942 | | | $ | (9,915) | | | $ | 2,531,209 | |
| Net Income | | Net Income | | 217,425 | | | 217,425 | |
| Other Comprehensive Income(Loss), Net of Tax | | Other Comprehensive Income(Loss), Net of Tax | | 7,031 | | | 7,031 | |
| Dividends Declared to Parent | | Dividends Declared to Parent | | (100,000) | | | (100,000) | |
| | Balances as of December 31, 2022 | | Balances as of December 31, 2022 | $ | 1,696,539 | | | $ | (6,357) | | | $ | 968,367 | | | $ | (2,884) | | | $ | 2,655,665 | |
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 438,000443,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.
BASIS OF PRESENTATION
TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission facilitiessystems 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. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows.
Accounting for Regulated Operations
TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates charged to retail customers or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities 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:
•Anan independent regulator sets rates;
•Thethe regulator sets the rates to recover the specific enterprise’s costs of providing service; and
•Ratesrates 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 the primary beneficiary of the VIEs on a quarterly basis.
As of December 31, 2021,2022, 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
In 2020, the FASB issued Accounting Standards Update (ASU) 2020-04 establishing Accounting Standards Codification (ASC) Topic 848, Reference Rate Reform, and in 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (collectively, ASC 848). ASC 848 contains practical expedients for reference rate reform related activities that impact debt, leases, derivatives and other contracts. The guidance in ASC 848 is optional and may be elected over time as reference rate reform activities occur. In 2022, the FASB issued ASU 2022-06, Deferral of the Sunset Date of Topic 848 (ASU 2022-06), to defer the sunset date of ASC 848 to December 31, 2024. ASU 2022-06 is effective immediately for all companies. TEP continues to evaluate the impact of ASC 848.
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 legal proceedings and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
CASH AND CASH EQUIVALENTS
TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RESTRICTED CASH
Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
on the balance sheet and reconciles their sum to the cash flow statement: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Cash and Cash Equivalents | Cash and Cash Equivalents | $ | 10 | | | $ | 61 | | | $ | 10 | | Cash and Cash Equivalents | $ | 16 | | | $ | 10 | | | $ | 61 | |
| Restricted Cash included in: | Restricted Cash included in: | | Restricted Cash included in: | |
| Investments and Other Property | Investments and Other Property | 20 | | | 19 | | | 16 | | Investments and Other Property | 22 | | | 20 | | | 19 | |
| Current Assets—Other | Current Assets—Other | 3 | | | 2 | | | 2 | | Current Assets—Other | 13 | | | 3 | | | 2 | |
| Total Cash, Cash Equivalents, and Restricted Cash | Total Cash, Cash Equivalents, and Restricted Cash | $ | 33 | | | $ | 82 | | | $ | 28 | | Total Cash, Cash Equivalents, and Restricted Cash | $ | 51 | | | $ | 33 | | | $ | 82 | |
Restricted cash included in Investments and Other Property on the Consolidated Balance Sheetsprimarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning 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.Juan.
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 receivablereceivables 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 facilities and transmission and distribution facilities.systems. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction.
The cost of repairs and maintenance, including planned generation facility overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred.
When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced byby: (i) the original costcost; (ii) plus removal costscosts; (iii) 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.rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The average AFUDC rates on regulated construction expenditures are included in the table below: | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Average AFUDC Rates | 6.88 | % | | 6.63 | % | | 7.86 | % |
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 |
| Average AFUDC Rates | 6.74 | % | | 6.88 | % | | 6.63 | % |
Depreciation
Depreciation is recorded for owned utility plant on a group method straight-line basis, excluding software intangible plant, at depreciation rates based on the economic lives of the assets, including estimates for salvage value and removal costs. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation facilities, distribution systems, and general plant assets. Transmission system assets are subject to the jurisdiction of the FERC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Below are the summarized average annual depreciation rates for all utility plant: | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Average Annual Depreciation Rates | 3.30 | % | | 3.15 | % | | 3.08 | % |
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 |
| Average Annual Depreciation Rates | 3.24 | % | | 3.30 | % | | 3.15 | % |
Computer Software and Cloud Computing Costs
Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over three to five years. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is impaired, the carrying value is reduced and recorded as an expense 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 printingfiling 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.
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, except during service disconnection moratoriums. No component of the transaction price is allocated to unsatisfied performance obligations.
TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which it expects to be entitled and recognizes a refund liability until it is certain it will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods.
LEASES
When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
performance obligation over time as power is deliveredTEP has operating leases for office facilities, land, rail cars, and control is transferred to the customer. The Company bills for power sales basedcommunication tower space thatare included on the readingbalance sheet as follows: | | | | | | | | | | | | | |
| | | December 31, |
| (in millions) | | | 2022 | | 2021 |
| Lease Assets | | | | | |
| | | | | |
| | | | | |
| Regulatory and Other Assets, Other | | | $ | 6 | | | $ | 7 | |
| Lease Liabilities | | | | | |
| | | | | |
| | | | | |
| Current Liabilities, Other | | | 1 | | | 1 | |
| Regulatory and Other Liabilities, Other | | | 5 | | | 6 | |
As of electric meters on a systematic basis throughout the month. In general,December 31, 2022, TEP's contracts have payment terms of 10future minimum operating lease payments, excluding payments to 20 dayslessors for variable costs, are $1 million or less in each year from the date the bill is rendered. TEP considers any payment not received by the due date delinquent2023 through 2027 and charges the customer a late payment fee, except during 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 it expects to be entitled and recognizes a refund liability until it is certain it will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods. See Note 4 for the disaggregation of TEP's Operating Revenues.$3 million thereafter.
PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE
TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities, and cost under-recoveries are deferred as regulatory assets. 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 requirementssales 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. As of February 10, 2022, the ACC has not set annual target retail kWh savings requirements for future years. The associated lost revenues attributable to meeting these targetsthe EE Standards 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.
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, | | December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | (in millions) | 2022 | | 2021 |
| Beginning of Period | Beginning of Period | $ | 66 | | | $ | 63 | | Beginning of Period | $ | 69 | | | $ | 66 | |
| Purchased | Purchased | 49 | | | 48 | | Purchased | 58 | | | 49 | |
| Used for Compliance | Used for Compliance | (46) | | | (45) | | Used for Compliance | (45) | | | (46) | |
| End of Period | End of Period | $ | 69 | | | $ | 66 | | End of Period | $ | 82 | | | $ | 69 | |
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TAXES OTHER THAN INCOME TAXES
TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
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 paid $3 million in December 2021 and expects to pay the remaining deferred deposits to the IRS in 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 $5 million and $6 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. 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 $1 million and $2 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. 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.
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 thean asset for a defined benefit plan's overfunded status or a liability for a plan's underfunded status of defined benefit plans as a liability in the balance sheet. The underfundedfunded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement plan. 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 not yet recognized in the income statement 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
TAXES OTHER THAN INCOME TAXES
TEP acts as a conduit or collection agent for additional information regarding derivative instruments.sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
INCOME TAXES
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized.
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income.
Federal ITCs are deferred and amortized as a reduction to income tax expense over the life of the underlying asset.All other federal and state income tax credits, including PTCs, are treated as a reduction to income tax expense in the year the credit arises.
NOTE 2. REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission facilities,systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.
RATE CASE MATTERS
20202022 Rate OrderCase
In June 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021.
TEP's key 2022 Rate Case proposals are described below:
•a $136 million net increase in retail revenues comprised of the following components:
◦a non-fuel retail revenue increase of $159 million over test year non-fuel retail revenues;
◦a $66 million increase in fuel-related retail revenues, offset by a $71 million reduction in PPFAC revenues; and
◦changes in certain adjustor mechanisms, including DSM, ECA, and RES, which result in an $18 million reduction in revenues.
•a 7.31% return on original cost rate base of $3.6 billion, which includes a cost of equity of 10.25% and an average cost of debt of 3.82%; and
•a new RTM adjustor that is designed to provide more timely recovery of TEP's clean energy investments and replace the ECA.
TEP requested new rates to be implemented by September 1, 2023. TEP cannot predict the timing or outcome of this proceeding.
2020 ACC Phase 2 Proceedings
In 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%; and
•a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt.
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. In 2021, there was limited activity in this docket. On January 19, 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. TEP cannot predictIn January 2023, the timing or outcomeACC closed Phase 2 and ordered that just and equitable transition issues be considered as part of these proceedings.the 2022 Rate Case.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20192022 Final FERC Rate CaseOrder
In 2019, TEP filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for timely recovery of transmission-related costs. The FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the 2022 Final FERC Rate Order, the FERC established hearing and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.
Provisions of the ordersettlement agreement include, but are not limited to:
•replacing TEP's stated transmission rates with a single forward-looking formula rate;
•a 10.4%9.79% 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. In February 2021, a Presiding Judge was appointed to continue the formula rate case proceeding after the settlement procedures resulted in an impasse. In August 2021, TEP filed an unopposed motion requesting that the Chief Judge suspend the litigation procedural schedule to allow the parties time to prepare and file a comprehensive settlement package, as parties in the proceeding reached a settlement in principle. The motion was granted and in December 2021 the settlement agreement was filed with the FERC. On February 1, 2022, the Presiding Judge certified and recommended approval by the FERC of the proposed settlement.
Provisions of the proposed settlement include, but are not limited to:
•replacing TEP's stated transmission rates with a single forward-looking formula rate;
•a 9.79% return on equity;
•elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor;
•a direct assignment of 25% of transmission costs allocated to retail customers and 75% allocated between wholesale and retail customers beginning January 1, 2022, through the date that is the later of: (i) December 31, 2031; or (ii) the date on which TEP has no Industrial Development Revenue Bonds outstanding;
•a refund of the difference in rates for the period commencing August 1, 2019 through December 31, 2021; and
•$4 million in costs related to the abandoned Nogales transmission line to be amortized over 10 years.
As a result of the proposed settlement, in December 2021 TEP recognized: (i) $12 million of wholesale revenue, which includes $4 million and $3 million for transmission service provided in 2020 and 2019, respectively; and (ii) a decrease of $3 million in alternative revenues. The agreement does not go into effect until final approval from the FERC is received. TEP cannot predict the final timing of the proceedings. AllIncreased rates charged under the revised OATT pursuant to the2022 Final FERC order areRate Order were subject to refund untiland deferred as a regulatory liability. In 2022, TEP returned all amounts in excess of the proceeding concludes.rates approved in the settlement agreement previously deferred as a regulatory liability. TEP had $15 million ofno wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2022, and $15 million reserved as of December 31, 2021, and 2020.related to the 2022 Final FERC Rate Order.
OTHER FERC MATTERS
In January 2021, the FERC notified TEP that it was commencing an audit that intendswith the intent to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit coverscovered the period of January 1, 2018, to December 31, 2021. On November 4, 2022, the present. TheFERC published without prejudice the final audit is ongoingreport with its findings and recommendations. TEP cannot predictaccepted the outcome or findings if any,therein and submitted compliance items related to the audit in January 2023. TEP does not expect a material financial impact from the results of the FERC audit at this time.audit.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
period. On February 1,In April 2022, TEP filed a request with the ACC for approval ofapproved a rate adjustment for the PPFAC. The request presents two additional scenarios wherebyPPFAC that sets the true-up component of the PPFAC rate is reset to reflectrecover the recovery of theexisting uncollected true-up balance over 18 and 24-month timeframes. TEP cannot predictmonths. The ACC also set the outcomeforward-looking component of the proceeding.PPFAC rate to zero, which has resulted in under-collection of PPFAC costs.
The table below summarizes the PPFAC regulatory asset (liability) balance: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | (in millions) | 2022 | | 2021 |
| Beginning of Period | Beginning of Period | $ | 23 | | | $ | 36 | | Beginning of Period | $ | 91 | | | $ | 23 | |
Deferred Fuel and Purchased Power Costs (1) | Deferred Fuel and Purchased Power Costs (1) | 343 | | | 283 | | Deferred Fuel and Purchased Power Costs (1) | 348 | | | 343 | |
PPFAC and Base Power Recoveries (2) | PPFAC and Base Power Recoveries (2) | (275) | | | (296) | | PPFAC and Base Power Recoveries (2) | (315) | | | (275) | |
| End of Period | End of Period | $ | 91 | | | $ | 23 | | End of Period | $ | 124 | | | $ | 91 | |
(1)Includes costs eligible for recovery through the PPFAC and base power rates.
(2)In March 2021, and 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request which went into effectbeginning in June 2021. The 2022 PPFAC rate adjustment became effective on June 1, 2021 and June 1, 2020.April 29, 2022.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Costs eligible costs for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. Beginning January 2021, theThe difference between costs recovered through rates and actual ECA eligible costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a balancing account as approved as part ofregulatory asset to recover from customers in the 2020future. The 2022 Rate Order.Case includes a proposal to transition away from the current ECA surcharge and to recover the costs in base rates.
Tax Expense Adjustor Mechanism
The TEAM allows for the timely recovery of future significant income tax changes. Itchanges and provides the Company the ability to pass through as a kWh surcharge: (i) the TCJA Regulatory Deferral balance to the initial 2021 TEAM rate; (ii) the change in EDIT compared to the test year; and (iii)(ii) the income tax effects of tax legislation that materially impacts TEP's 2018 test yearauthorized revenue requirements. The TEAM went into effect January 1, 2021, as approved in the 2020 Rate Order. In 2021, TEP refunded $29 million to customers through the TEAM.
Federal Tax Legislation
In 2018, the ACC approved TEP’s proposal to return savings from TEP’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 reflected the return of a portion of the savings. As part of the 2020 Rate Order, the balances in the regulatory liability deferral and TCJA balancing account were moved to the TEAM regulatory account in December 2020.requirement.
Transmission Cost Adjustor
The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January. The TCA went into effect January 1, 2021, as approved in the 2020 Rate Order.of each year.
OnIn February 8, 2022, the ACC approved TEP's motion to modify the TCA Planplan of Administrationadministration to reflect the terms of the 20192022 Final FERC Rate Case proposedOrder settlement agreement, pending the conclusion of that proceeding.agreement.
Renewable Energy Standard
The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2022 was 12% of retail electric sales. In 2022, the percentage of TEP's retail kWh sales attributable to the RES was approximately 24%. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. The renewable energy requirement in 2021 was 11%TEP recovers approved costs of carrying out this plan from retail electric sales. In 2021, the percentage of TEP's retail kWh sales attributable to thecustomers through a RES was approximately 26%.surcharge.
In September 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
incentives for customer-installed DG; and (iii) various other program costs. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal by July 1, 2022, to phase out the RES tariff. In June 2022, TEP filed a request with the ACC for approval of an extension of the 2021 RES implementation plan through the completion of the 2022 Rate Case. The rate case includes a proposal to transition away from the current RES surcharge and to recover the costs in base rates.
Energy Efficiency Standards
Under the EE Standards, the ACC requires electric utilitiesTEP is required to implement cost-effective DSM programs to reduce customers' energy consumption. As of December 31, 2021, TEP's cumulativecomply 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 energy savings was approximately 23%. Theperformance incentive. TEP records its annual DSM performance incentive for the prior calendar year is recorded in the first quarter of each year. As of December 31, 2022, TEP's cumulative annual energy savings were approximately 24%.
In 2019,November 2022, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of $23 million, which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standards. 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 2021, TEP filed its 2022 energy efficiency implementation plan, with a budget of approximately $23 million. TEP cannot predict$24 million, which is collected through the outcome ofDSM surcharge. The 2022 plan will remain in effect until another plan is approved. The 2022 Rate Case includes a proposal to transition away from the proceeding.current DSM surcharge and to recover the costs in base rates.
In 2022, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings over three years.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG.The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. In 2021, LFCR revenues decreased as a result of a rate adjustment as approved in the 2020 Rate Order. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded inon the balance sheet are summarized in the table below: | | | Remaining Recovery Period (years) | | December 31, | | Remaining Recovery Period (years) | | December 31, |
| ($ in millions) | ($ in millions) | | 2021 | | 2020 | ($ in millions) | | 2022 | | 2021 |
| Regulatory Assets | Regulatory Assets | | | | | | Regulatory Assets | | | | | |
| Pension and Other Postretirement Benefits (Note 10) | Various | | $ | 128 | | | $ | 166 | | |
| Under Recovered Purchased Energy Costs | Under Recovered Purchased Energy Costs | 2 | | 91 | | | 23 | | Under Recovered Purchased Energy Costs | 2 | | $ | 124 | | | $ | 91 | |
| Pension and Other Postretirement Benefits (Note 9) | | Pension and Other Postretirement Benefits (Note 9) | Various | | 90 | | | 128 | |
Early Generation Retirement Costs | Early Generation Retirement Costs | Various | | 38 | | | 43 | | Early Generation Retirement Costs | Various | | 58 | | | 38 | |
Property Tax Deferrals (2) | | Property Tax Deferrals (2) | 1 | | 29 | | | 27 | |
| Lost Fixed Cost Recovery | Lost Fixed Cost Recovery | 1 | | 37 | | | 59 | | Lost Fixed Cost Recovery | 1 | | 25 | | | 37 | |
Property Tax Deferrals (1) | 1 | | 27 | | | 26 | | |
Income Taxes Recoverable through Future Rates (2) | Various | | 17 | | | 27 | | |
Final Mine Reclamation and Retiree Healthcare Costs (3) | Final Mine Reclamation and Retiree Healthcare Costs (3) | 7 | | 17 | | | 20 | | Final Mine Reclamation and Retiree Healthcare Costs (3) | 6 | | 11 | | | 17 | |
| Derivatives (Note 13) | 8 | | 8 | | | 55 | | |
Springerville Unit 1 Leasehold Improvements (4) | 2 | | 4 | | | 7 | | |
Income Taxes Recoverable through Future Rates (4) | | Income Taxes Recoverable through Future Rates (4) | Various | | 6 | | | 17 | |
| Unamortized Loss on Reacquired Debt | | Unamortized Loss on Reacquired Debt | Various | | 5 | | | 5 | |
| Derivatives (Note 12) | | Derivatives (Note 12) | 7 | | 3 | | | 8 | |
| Tax Expense Adjustor Mechanism | Tax Expense Adjustor Mechanism | 1 | | 3 | | | — | | Tax Expense Adjustor Mechanism | 1 | | 3 | | | 3 | |
Springerville Unit 1 Leasehold Improvements (5) | | Springerville Unit 1 Leasehold Improvements (5) | 1 | | 2 | | | 4 | |
| Other Regulatory Assets | Other Regulatory Assets | Various | | 14 | | | 16 | | Other Regulatory Assets | Various | | 14 | | | 9 | |
| Total Regulatory Assets | Total Regulatory Assets | | 384 | | | 442 | | Total Regulatory Assets | | 370 | | | 384 | |
| Less Current Portion | Less Current Portion | 1 | | 116 | | | 124 | | Less Current Portion | 1 | | 185 | | | 116 | |
| Total Non-Current Regulatory Assets | Total Non-Current Regulatory Assets | | $ | 268 | | | $ | 318 | | Total Non-Current Regulatory Assets | | $ | 185 | | | $ | 268 | |
| | Regulatory Liabilities | Regulatory Liabilities | | Regulatory Liabilities | | | | |
Income Taxes Payable through Future Rates (2)(4) | Income Taxes Payable through Future Rates (2)(4) | Various | | $ | 268 | | | $ | 298 | | Income Taxes Payable through Future Rates (2)(4) | Various | | $ | 244 | | | $ | 268 | |
Net Cost of Removal (5) | Various | | 73 | | | 125 | | |
| Derivatives (Note 12) | | Derivatives (Note 12) | 7 | | 86 | | | 19 | |
| Renewable Energy Standard | Renewable Energy Standard | Various | | 66 | | | 63 | | Renewable Energy Standard | Various | | 73 | | | 66 | |
| Derivatives (Note 13) | 8 | | 19 | | | 4 | | |
| Transmission Revenue Subject to Refund—FERC | 1 | | 15 | | | 15 | | |
Net Cost of Removal (6) | | Net Cost of Removal (6) | Various | | 43 | | | 73 | |
| Demand Side Management | Demand Side Management | 1 | | 12 | | | 6 | | Demand Side Management | 1 | | 16 | | | 12 | |
| Transmission Cost Adjustor | | Transmission Cost Adjustor | 1 | | 9 | | | 9 | |
| Pension and Other Postretirement Benefits (Note 9) | | Pension and Other Postretirement Benefits (Note 9) | Various | | 8 | | | — | |
| Deferred Investment Tax Credits | | Deferred Investment Tax Credits | Various | | 7 | | | 1 | |
| | Transmission Cost Adjustor | 1 | | 9 | | | — | | |
| Tax Expense Adjustor Mechanism | 1 | | — | | | 29 | | |
| Transmission Revenue Subject to Refund - FERC | | Transmission Revenue Subject to Refund - FERC | 1 | | 1 | | | 15 | |
| Other Regulatory Liabilities | Other Regulatory Liabilities | Various | | 1 | | | 1 | | Other Regulatory Liabilities | Various | | 2 | | | — | |
| Total Regulatory Liabilities | Total Regulatory Liabilities | | 463 | | | 541 | | Total Regulatory Liabilities | | 489 | | | 463 | |
| Less Current Portion | Less Current Portion | 1 | | 111 | | | 151 | | Less Current Portion | 1 | | 111 | | | 111 | |
| Total Non-Current Regulatory Liabilities | Total Non-Current Regulatory Liabilities | | $ | 352 | | | $ | 390 | | Total Non-Current Regulatory Liabilities | | $ | 378 | | | $ | 352 | |
(1)Increase in Early Generation Retirement Costs is primarily due to the retirement of San Juan Unit 1 in June 2022.
(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.
(2)Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 14 for additional information regarding income taxes.
(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. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022.
(4)Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 13 for additional information regarding income taxes.
(5)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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6)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 a result of the 2020 Rate
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Order, TEP transferred costs fromThe decrease in Net Cost of Removal is primarily due to Accumulated Depreciation and Amortization. See Note 3 for additional information related to new depreciation rates approved as partthe retirement of the 2020 Rate Order.San Juan Unit 1 in June 2022.
Regulatory Assets and Liabilities
With the exception ofExcept for Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Springerville Unit 1 Leasehold Improvements, and Under Recovered Purchased Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.
IMPACTS OF REGULATORY ACCOUNTING
If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.
NOTE 3. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Plant in Service on the Consolidated Balance Sheets by major class: | | | Annual Depreciation Rate (3) | | Average Remaining Life in Years (3) | | December 31, | | Annual Depreciation Rate (4) | | Average Remaining Life in Years (4) | | December 31, |
| ($ in millions) | ($ in millions) | | 2021 | | 2020 | ($ in millions) | | 2022 | | 2021 |
| Plant in Service | Plant in Service | | | | | | | | Plant in Service | | | | | | | |
Generation Plant | Generation Plant | 3.11% | | 18 | | $ | 3,753 | | | $ | 3,279 | | Generation Plant | 3.11% | | 17 | | $ | 3,491 | | | $ | 3,753 | |
| Distribution Plant | Distribution Plant | 1.93% | | 33 | | 2,024 | | | 1,906 | | Distribution Plant | 1.93% | | 32 | | 2,149 | | | 2,024 | |
| Transmission Plant | Transmission Plant | 1.69% | | 35 | | 1,210 | | | 1,090 | | Transmission Plant | 1.69% | | 34 | | 1,295 | | | 1,210 | |
| General Plant | General Plant | 6.01% | | 7 | | 540 | | | 503 | | General Plant | 6.01% | | 6 | | 653 | | | 540 | |
Intangible Plant, Software Costs, and Other (1)(2) | Intangible Plant, Software Costs, and Other (1)(2) | Various | | Various | | 268 | | | 291 | | Intangible Plant, Software Costs, and Other (1)(2) | Various | | Various | | 224 | | | 268 | |
| Plant Held for Future Use | Plant Held for Future Use | — | | — | | 3 | | | 4 | | Plant Held for Future Use | — | | — | | 2 | | | 3 | |
Total Plant in Service (2)(3) | Total Plant in Service (2)(3) | | $ | 7,798 | | | $ | 7,073 | | Total Plant in Service (2)(3) | | $ | 7,814 | | | $ | 7,798 | |
|
(1)In June 2022, San Juan Unit 1 was retired by PNM, the operator of San Juan. Contemporaneously, TEP's obligations ceased with respect to: (i) costs incurred for San Juan Unit 1 and the related common facilities stemming from continued operations at San Juan; and (ii) purchases under the coal supply agreement between PNM and San Juan Coal Company.
(2)Primarily represents computer software, which is amortized over three to five years for smaller application software and 10 years for large enterprise software and has an average remaining life of three years.
(2)(3)Includes plant acquisition adjustments of $(206) million and $(202) million as of December 31, 20212022 and 2020, respectively.2021.
(3)(4)Based on the 2018 depreciation study available for the major classes of Plant in Service, effective January 1, 2021, as approved as part of the 2020 Rate Order. Transmission Plant depreciation rates are based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 20192022 Final FERC Rate Case.Order.
Generation Plant
Oso Grande
In 2019, TEP entered into a BTA to develop Oso Grande. In May 2021, Oso Grande was placed in service, adding 250 MW of wind-powered electric generation, increasing TEP's total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 700 MW. As of December 31, 2021, there was $444 million in costs related to Oso Grande in Plant in Service on the Consolidated Balance Sheets.
Springerville Common Facilities
In 2020, due to expiring leases, TEP purchased 32.2% in undivided interests in facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities) at a total fixed purchase price of $68 million. The transaction resulted in an increase in Plant in Service and a decrease in Utility Plant Under Finance Leases on the Consolidated Balance Sheets.
As a condition of the purchase, Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, purchased a 14% undivided interest in the Springerville Common Facilities for $30 million in 2020. Also, Tri-State, the lessee of Springerville Unit 3, was obligated to either: (i) buy a 14% undivided interest in the facilities for
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
$30 million by December 31, 2021; or (ii) continue to make payments to TEP for the use of these facilities. Tri-State did not exercise its purchase option and therefore will continue to make payments to TEP.
RICE Units
Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed into service 10 natural gas RICE units with a total nominal generation capacity of 188 MW in 2020. As of December 31, 2021, there was $187 million related to the Sundt RICE units recorded in Plant in Service on the Consolidated Balance Sheets.
Accumulated Depreciation and Amortization
TEP Depreciation Rates
As part of the 2020 Rate Order, effective January 2021, TEP reclassified $33 million from Regulatory and Other Liabilities—Regulatory Liabilities to Accumulated Depreciation and Amortization on the Consolidated Balance Sheets to reflect the impact of the revised depreciation rates on estimated cost of removal.
Amortization of Intangible Plant
Intangible Plant primarily consists of computer software. Accumulated amortization of computer software costs were $169was $110 million and $199$169 million as of December 31, 20212022 and 2020,2021, respectively. Amortization of computer software costs totaled $30 million in 2022, $33 million in 2021, and $29 million in 2020, and $26 million in 2019.2020. Future estimated amortization costs for existing computer software are $26 million in 2022, $19 million in 2023, $12$18 million in 2024, $7$14 million in 2025, $10 million in 2026, and $4 million in 2026.2027.
Intangible Plant includes $(4) million in acquisition discounts not subject to amortization as of December 31, 2021,2022 and none in 2020.2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
JOINTLY-OWNED FACILITIES
As of December 31, 2021,2022, TEP was a participant in the following jointly-owned generation facilities and transmission systems: | | ($ in millions) | ($ in millions) | Ownership Percentage | | Plant in Service | | Construction Work in Progress | | Accumulated Depreciation | | Net Book Value | ($ in millions) | Ownership Percentage | | Plant in Service | | Construction Work in Progress | | Accumulated Depreciation | | Net Book Value |
| San Juan Unit 1 | 50.0% | | $ | 285 | | | $ | 1 | | | $ | (269) | | | $ | 17 | | |
| Four Corners Units 4 and 5 | Four Corners Units 4 and 5 | 7.0% | | 188 | | | 4 | | | (81) | | | 111 | | Four Corners Units 4 and 5 | 7.0% | | $ | 191 | | | $ | 5 | | | $ | (88) | | | $ | 108 | |
| Luna | Luna | 33.3% | | 59 | | | 1 | | | (3) | | | 57 | | Luna | 33.3% | | 57 | | | — | | | 1 | | | 58 | |
| Gila River Unit 3 | Gila River Unit 3 | 75.0% | | 206 | | | — | | | (65) | | | 141 | | Gila River Unit 3 | 75.0% | | 204 | | | 2 | | | (63) | | | 143 | |
| Gila River Common Facilities | Gila River Common Facilities | 43.8% | | 75 | | | 1 | | | (26) | | | 50 | | Gila River Common Facilities | 43.8% | | 75 | | | — | | | (28) | | | 47 | |
| Springerville Coal Handling Facilities | Springerville Coal Handling Facilities | 83.0% | | 209 | | | — | | | (95) | | | 114 | | Springerville Coal Handling Facilities | 83.0% | | 207 | | | — | | | (98) | | | 109 | |
| Springerville Common Facilities | Springerville Common Facilities | 86.0% | | 399 | | | — | | | (207) | | | 192 | | Springerville Common Facilities | 86.0% | | 404 | | | 1 | | | (218) | | | 187 | |
| Transmission Facilities | Transmission Facilities | Various | | 462 | | | 20 | | | (229) | | | 253 | | Transmission Facilities | Various | | 551 | | | 16 | | | (234) | | | 333 | |
| Total | Total | | $ | 1,883 | | | $ | 27 | | | $ | (975) | | | $ | 935 | | Total | | $ | 1,689 | | | $ | 24 | | | $ | (728) | | | $ | 985 | |
As a participant in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs. 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 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, | | December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | (in millions) | 2022 | | 2021 |
| Beginning of Period | Beginning of Period | $ | 96 | | | $ | 107 | | Beginning of Period | $ | 139 | | | $ | 96 | |
Liabilities Incurred (1) | Liabilities Incurred (1) | 14 | | | — | | Liabilities Incurred (1) | 1 | | | 14 | |
Liabilities Settled (2) | Liabilities Settled (2) | (2) | | | (5) | | Liabilities Settled (2) | (8) | | | (2) | |
| Regulatory Deferral/Accretion Expense | Regulatory Deferral/Accretion Expense | 4 | | | 4 | | Regulatory Deferral/Accretion Expense | 5 | | | 4 | |
Revisions to the Present Value of Estimated Cash Flows (3) | Revisions to the Present Value of Estimated Cash Flows (3) | 27 | | | (10) | | Revisions to the Present Value of Estimated Cash Flows (3) | (16) | | | 27 | |
| End of Period | End of Period | $ | 139 | | | $ | 96 | | End of Period | $ | 121 | | | $ | 139 | |
(1)Asset retirement obligationIn 2021, TEP incurred an ARO for Oso Grande,Grande. In 2022, TEP incurred an ARO for new photovoltaic generation placed in service in May 2021.service.
(2)Primarily related to the retirement of Navajo.
(3)Primarily related to changes due to revised decommissioning estimates of the timing of cash flows required to settle future liabilities offor San Juan and changes in ownership of Springerville Common Facilities.Juan.
NOTE 4. REVENUE
TEP earns the majoritymost of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DISAGGREGATION OF REVENUES
The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Retail | Retail | $ | 1,088 | | | $ | 1,039 | | | $ | 972 | | Retail | $ | 1,140 | | | $ | 1,088 | | | $ | 1,039 | |
Wholesale | Wholesale | 278 | | | 190 | | | 247 | | Wholesale | 456 | | | 278 | | | 190 | |
| Other Services | Other Services | 114 | | | 95 | | | 124 | | Other Services | 104 | | | 114 | | | 95 | |
| Revenues from Contracts with Customers | Revenues from Contracts with Customers | 1,480 | | | 1,324 | | | 1,343 | | Revenues from Contracts with Customers | 1,700 | | | 1,480 | | | 1,324 | |
| Alternative Revenues | Alternative Revenues | 12 | | | 48 | | | 35 | | Alternative Revenues | 28 | | | 12 | | | 48 | |
| Other | Other | 101 | | | 53 | | | 40 | | Other | 80 | | | 101 | | | 53 | |
| Total Operating Revenues | Total Operating Revenues | $ | 1,593 | | | $ | 1,425 | | | $ | 1,418 | | Total Operating Revenues | $ | 1,808 | | | $ | 1,593 | | | $ | 1,425 | |
(1)Change primarily due to an increase in forward market prices.
Retail Revenues
TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during the spring and summer months andthen 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 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.
Pursuant to a FERC order, all rates charged under TEP's revised OATT are subject to refund until the 2019 FERC Rate Case proceedings conclude. Wholesale Revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 20192022 Final FERC Rate Case.Order.
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 and the Springerville Coal Handling Facilities by the operatorlessee of Springerville Unit 3. When TEP recognizes revenue for reimbursement of Springerville Common Facilities3, 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.miscellaneous service-related revenues.
Alternative Revenues
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR, TCA and ECA mechanisms, andLFCR, DSM performance incentive, and OATT balancing activity as alternative revenues. See Note 2 for additional information regarding these cost recovery mechanisms and performance incentive.
Other Revenues
Other Revenues include gains and losses on derivative contracts, common cost allocations to affiliates, and asset management agreement service fees, late and optimization gains.returned payment finance charges and common cost allocations to affiliates. See Note 6 for information regarding revenue from related parties and Note 1312 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, | | December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | (in millions) | 2022 | | 2021 |
| Retail | Retail | $ | 78 | | | $ | 90 | | Retail | $ | 87 | | | $ | 78 | |
| Retail, Unbilled | Retail, Unbilled | 44 | | | 41 | | Retail, Unbilled | 46 | | | 44 | |
| Retail, Allowance for Credit Losses | Retail, Allowance for Credit Losses | (10) | | | (13) | | Retail, Allowance for Credit Losses | (9) | | | (10) | |
Wholesale (1) | Wholesale (1) | 47 | | | 33 | | Wholesale (1) | 132 | | | 47 | |
| Due from Affiliates (Note 6) | Due from Affiliates (Note 6) | 17 | | | 9 | | Due from Affiliates (Note 6) | 26 | | | 17 | |
| Other | Other | 17 | | | 13 | | Other | 39 | | | 17 | |
| Accounts Receivable | Accounts Receivable | $ | 193 | | | $ | 173 | | Accounts Receivable | $ | 321 | | | $ | 193 | |
(1)Includes $16$52 million and $7$16 million as of December 31, 20212022 and 2020,2021, respectively, of receivables related to revenue from derivative instruments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ALLOWANCE FOR CREDIT LOSSES
TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Consolidated Balance Sheets: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | (in millions) | 2022 | | 2021 |
| Beginning of Period | Beginning of Period | $ | (13) | | | $ | (6) | | Beginning of Period | $ | (10) | | | $ | (13) | |
Credit Loss Expense | Credit Loss Expense | — | | | (10) | | Credit Loss Expense | (5) | | | — | |
Write-offs | Write-offs | 3 | | | 3 | | Write-offs | 6 | | | 3 | |
| | End of Period | End of Period | $ | (10) | | | $ | (13) | | End of Period | $ | (9) | | | $ | (10) | |
Service Disconnection Moratoriums(1)Credit loss expense increased due to a disconnection moratorium.
In 2019,(2)Write-offs increased due to the ACC enacted emergency rules that suspended service disconnections and late fees for electric residential customers who would have otherwise been eligible for service disconnectionexpiration of a payment plan offered during the period from June 1 through October 15 (Summer Moratorium). The Summer Moratorium remained in effect for 2020 and 2021, and was permanently adopted by the ACC in November 2021. In addition, as a result of the COVID-19 pandemic, TEP voluntarily suspended service disconnections and late fees from March 2020 through January 2021 for all customers who would have otherwise been eligible for disconnection.
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
Customer Payment Assistance
In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $15 million DES payment assistance funds in the program included: (i) an upfront bill credit applied to theiryear ended December 2020 bill; and (ii) automatic enrollment into an eight-month payment plan. TEP also voluntarily created payment arrangements for commercial customers affected by31, 2022. Funds received directly reduced Accounts Receivable on the COVID-19 pandemic. In the second quarter of 2021, TEP began experiencing accounts receivable collection activity consistent with pre-COVID-19 pandemic conditions and has made significant progress towards collecting aged accounts receivable from these customers.
TEP is continuing to monitor collection activity and adjusting its allowance for credit losses as needed.Consolidated Balance Sheets.
NOTE 6. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services. Effective January 2021, TEP hired SES's employees and will no longer utilize SES's 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) | 2021 | | 2020 |
| Receivables from Related Parties | | | |
| | | |
| UNS Electric | $ | 8 | | | $ | 6 | |
| UNS Energy | 7 | | | 2 | |
| UNS Gas | 2 | | | 1 | |
| Total Due from Related Parties | $ | 17 | | | $ | 9 | |
| | | |
| Payables to Related Parties | | | |
| UNS Energy | $ | 1 | | | $ | 1 | |
| UNS Gas | 1 | | | — | |
| SES | — | | | 4 | |
| | | |
| Total Due to Related Parties | $ | 2 | | | $ | 5 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets: | | | | | | | | | | | |
| December 31, |
| (in millions) | 2022 | | 2021 |
| Receivables from Related Parties | | | |
| | | |
| UNS Electric | $ | 22 | | | $ | 8 | |
| UNS Energy | 2 | | | 7 | |
| UNS Gas | 2 | | | 2 | |
| Total Due from Related Parties | $ | 26 | | | $ | 17 | |
| | | |
| Payables to Related Parties | | | |
| UNS Electric | $ | 5 | | | $ | — | |
| UNS Gas | 1 | | | 1 | |
| UNS Energy | 1 | | | 1 | |
| | | |
| Total Due to Related Parties | $ | 7 | | | $ | 2 | |
The following table presents the components of related party transactions included in the Consolidated Statements of Income: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Goods and Services Provided by TEP to Affiliates | Goods and Services Provided by TEP to Affiliates | | | | | | Goods and Services Provided by TEP to Affiliates | | | | | |
Transmission Revenues, UNS Electric (1) | Transmission Revenues, UNS Electric (1) | $ | 11 | | | $ | 9 | | | $ | 7 | | Transmission Revenues, UNS Electric (1) | $ | 5 | | | $ | 11 | | | $ | 9 | |
Wholesale Revenues, UNS Electric (1)(2) | Wholesale Revenues, UNS Electric (1)(2) | 25 | | | 1 | | | 1 | | Wholesale Revenues, UNS Electric (1)(2) | 50 | | | 25 | | | 1 | |
Control Area Services, UNS Electric (3) | Control Area Services, UNS Electric (3) | 6 | | | 4 | | | 4 | | Control Area Services, UNS Electric (3) | 3 | | | 6 | | | 4 | |
Common Costs, UNS Energy Affiliates (4) | Common Costs, UNS Energy Affiliates (4) | 21 | | | 19 | | | 19 | | Common Costs, UNS Energy Affiliates (4) | 22 | | | 21 | | | 19 | |
| | | Goods and Services Provided by Affiliates to TEP | Goods and Services Provided by Affiliates to TEP | | Goods and Services Provided by Affiliates to TEP | |
Wholesale Revenues, UNS Electric (1) | Wholesale Revenues, UNS Electric (1) | 1 | | | — | | | — | | Wholesale Revenues, UNS Electric (1) | 2 | | | 1 | | | — | |
Supplemental Workforce, SES (5) | Supplemental Workforce, SES (5) | — | | | 14 | | | 15 | | Supplemental Workforce, SES (5) | — | | | — | | | 14 | |
Corporate Services, UNS Energy (6) | Corporate Services, UNS Energy (6) | 7 | | | 5 | | | 6 | | Corporate Services, UNS Energy (6) | 8 | | | 7 | | | 5 | |
Corporate Services, UNS Energy Affiliates (7) | Corporate Services, UNS Energy Affiliates (7) | 3 | | | 4 | | | 4 | | Corporate Services, UNS Energy Affiliates (7) | 1 | | | 3 | | | 4 | |
Capacity Charges, UNS Gas (8) | Capacity Charges, UNS Gas (8) | — | | | — | | | 1 | | Capacity Charges, UNS Gas (8) | 1 | | | — | | | — | |
Corporate Services, Fortis Affiliates (9)(8) | Corporate Services, Fortis Affiliates (9)(8) | — | | | 1 | | | — | | Corporate Services, Fortis Affiliates (9)(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)In the second quarter of 2021, TEP began charging UNS Electric for capacity, power, and ancillary services under a tolling PPA. See Note 98 for additional information related to the tolling PPA. In May 2022, TEP began charging UNS Electric for power purchased in the EIM on behalf of UNS Electric.
(3)TEP charges UNS Electric for control area services under a FERC-approvedFERC-filed Control Area Services Agreement.
(4)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.
(5)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.
(6)Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $7 million in 2022, and $6 million in each of 2021 2020, and 2019.2020.
(7)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(9)(8)Fortis charges TEP for its share of payroll tax, insurance, and other costs paid by Fortis for affiliated employees.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 7. DEBT AND CREDIT AGREEMENTSAGREEMENT
DEBT
Long-term debt matures more than one year from the date of debt issuance. The following table presents the components of long-term debt, which includes Long-Term Debt, Net and Current Maturities of Long-Term Debt, Net on the Consolidated Balance Sheets: | | | December 31, | | December 31, |
| ($ in millions) | ($ in millions) | Interest Rate | | Maturity Date | | 2021 | | 2020 | ($ in millions) | Interest Rate | | Maturity Date | | 2022 | | 2021 |
| Notes | Notes | | | | | | | | Notes | | | | | | | |
| 2011 Senior Notes | 5.15% | | 2021 | | $ | — | | | $ | 250 | | |
| 2012 Senior Notes (1) | 2012 Senior Notes (1) | 3.85% | | 2023 | | 150 | | | 150 | | 2012 Senior Notes (1) | 3.85% | | 2023 | | $ | 150 | | | $ | 150 | |
| 2015 Senior Notes | | 2015 Senior Notes | 3.05% | | 2025 | | 300 | | | 300 | |
| 2020 Senior Notes | | 2020 Senior Notes | 1.50% | | 2030 | | 300 | | | 300 | |
| 2022 Senior Notes | | 2022 Senior Notes | 3.25% | | 2032 | | 325 | | | — | |
| 2014 Senior Notes | 2014 Senior Notes | 5.00% | | 2044 | | 150 | | | 150 | | 2014 Senior Notes | 5.00% | | 2044 | | 150 | | | 150 | |
| 2015 Senior Notes | 3.05% | | 2025 | | 300 | | | 300 | | |
| 2018 Senior Notes | 2018 Senior Notes | 4.85% | | 2048 | | 300 | | | 300 | | 2018 Senior Notes | 4.85% | | 2048 | | 300 | | | 300 | |
| 2020 Senior Notes | 2020 Senior Notes | 4.00% | | 2050 | | 350 | | | 350 | | 2020 Senior Notes | 4.00% | | 2050 | | 350 | | | 350 | |
| 2020 Senior Notes | 1.50% | | 2030 | | 300 | | | 300 | | |
| 2021 Senior Notes | 2021 Senior Notes | 3.25% | | 2051 | | 325 | | | — | | 2021 Senior Notes | 3.25% | | 2051 | | 325 | | | 325 | |
Tax-Exempt Local Furnishings Bonds (2) | | |
| Tax-Exempt Local Furnishings Bonds | | Tax-Exempt Local Furnishings Bonds | |
2013 Pima A | | 2013 Pima A | 4.00% | | 2029 | | 91 | | | 91 | |
| 2012 Pima A | 2012 Pima A | 4.50% | | 2030 | | 16 | | | 16 | | 2012 Pima A | 4.50% | | 2030 | | — | | | 16 | |
2013 Pima A | 4.00% | | 2029 | | 91 | | | 91 | | |
| Tax-Exempt Pollution Control Bonds | Tax-Exempt Pollution Control Bonds | | Tax-Exempt Pollution Control Bonds | |
2012 Apache A (3) | 4.50% | | 2030 | | 177 | | | 177 | | |
Total Long-Term Debt (4) | | 2,159 | | | 2,084 | | |
2012 Apache A | | 2012 Apache A | 4.50% | | 2030 | | — | | | 177 | |
Total Long-Term Debt (3) | | Total Long-Term Debt (3) | | 2,291 | | | 2,159 | |
| Less Unamortized Discount and Debt Issuance Costs | Less Unamortized Discount and Debt Issuance Costs | | 24 | | | 20 | | Less Unamortized Discount and Debt Issuance Costs | | 26 | | | 24 | |
| Less Current Maturities of Long-Term Debt | Less Current Maturities of Long-Term Debt | | — | | | 250 | | Less Current Maturities of Long-Term Debt | | 150 | | | — | |
| Total Long-Term Debt, Net | Total Long-Term Debt, Net | | $ | 2,135 | | | $ | 1,814 | | Total Long-Term Debt, Net | | $ | 2,115 | | | $ | 2,135 | |
(1)The 2012 Senior Notes are callable prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, the notes are2012 Senior Notes became callable at par plus accrued interest. The notes mature on March 15, 2023.
(2)The 2012 Pima A bonds become callable at par on or after June 1, 2022. The 2013 Pima A bonds become callable at par on or after March 1, 2023.
(3)The 2012 Apache A bonds become callable at par on or after March 1, 2022.
(4)As of December 31, 2021,2022, all of TEP's debt is unsecured.
Debt Issuances and Redemptions
In June 2022, TEP redeemed at par prior to maturity $16 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.
In March 2022, TEP redeemed at par prior to maturity $177 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum.
In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt in March 2022 and June 2022 and for general corporate purposes.
In August 2021, TEP redeemed at par prior to maturity $250 million aggregate principal amount of 5.15% senior unsecured notes, prior to maturity.notes.
In May 2021, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2051. TEP may redeem the notes prior to November 1, 2050, with a make-whole premium plus accrued interest. On or after November 1, 2050, TEP may redeem the debt at par plus accrued interest. TEP used the net proceeds to redeem debt in August 2021 and for general corporate purposes.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, the debt becomes callable at par plus accrued interest. TEP used the net proceeds from the sale: (i) to repay amounts outstanding under its credit agreement; (ii) to repay and terminate $225 million in term loans; and (iii) for general corporate purposes.
Maturities
Long-term debt matures on the following dates: | | (in millions) | (in millions) | Long-Term Debt (1) | (in millions) | Long-Term Debt (1) |
| 2022 | $ | — | | |
| 2023 | 2023 | 150 | | 2023 | $ | 150 | |
| 2024 | 2024 | — | | 2024 | — | |
| 2025 | 2025 | 300 | | 2025 | 300 | |
| 2026 | 2026 | — | | 2026 | — | |
| 2027 | | 2027 | — | |
| Thereafter | Thereafter | 1,709 | | Thereafter | 1,841 | |
| Total | Total | $ | 2,159 | | Total | $ | 2,291 | |
(1)Total long-term debt excludes $16$17 million of related unamortized debt issuance costs and $8$9 million of unamortized original issue discount.
CREDIT AGREEMENT
In October 2021, TEP entered into an unsecured credit agreement that provides for revolving credit commitments with swingline and LOC sublimits, due in October 2026, the termination date (2021 Credit Agreement). The final maturity date is subject to 2 one-yeartwo one-year extensions if certain conditions are satisfied. The 2021Amounts borrowed are recorded in Borrowings Under Credit Agreement amended and restated in its entiretyon the 2015 Credit Agreement.Consolidated Balance Sheets.
•Amounts borrowed under the 2021 Credit Agreement are used for working capital and other general corporate purposes and are recorded in Borrowings Under Credit Agreement on the Consolidated Balance Sheets. purposes.
•Interest rates and fees are based on a pricing grid tied to TEP's credit rating.
•LOCs are issued from time to time to support energy procurement, hedging transactions, and other business activities. The credit agreement provides for transitions to alternative benchmark rates.
Terms are as follows: | | | Sub-Limit Swingline(1) | | Sub-Limit LOC | | Weighted Average Interest Rate | | | Sub-Limit Swingline(1) | | Sub-Limit LOC | | Weighted Average Interest Rate | |
| | Capacity | | Borrowed(2) | | Available | | Pricing(3) | | Capacity | | Borrowed(2) | | Available | | Pricing(3)(4) |
| ($ in millions) | ($ in millions) | December 31, 2021 | ($ in millions) | December 31, 2022 |
| 2021 Agreement | 2021 Agreement | $ | 250 | | | $ | 15 | | | $ | 50 | | | $ | 25 | | | $ | 225 | | | 2.53 | % | | LIBOR + 1.000% | or ABR + 0.00% | 2021 Agreement | $ | 250 | | | $ | 15 | | | $ | 50 | | | $ | 5 | | | $ | 245 | | | — | % | | LIBOR + 1.025% | or ABR + 0.025% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | |
| ($ in millions) | December 31, 2021 |
| 2021 Agreement | $ | 250 | | | $ | 15 | | | $ | 50 | | | $ | 25 | | | $ | 225 | | | 2.53 | % | | LIBOR + 1.000% | or ABR + 0.00% |
(1)ABR pricing would apply to swingline loans.
(2)IncludesThe borrowed amounts include a $5 million LOC at a rate of 1.025% per annum as of December 31, 2022, and a $10 million LOC at a rate of 1.00% per annum as of December 31, 2021. This LOC was issued in October 2021 to replace LOCsan LOC originally issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the BTA.Grande. The LOC expires October 2023.
(3)TEP's pricing may be adjusted based on performance measured using two key performance indicators:sustainability targets: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Sub-Limit LOC | | | | | | Weighted Average Interest Rate | | | |
| Capacity | | | Borrowed(1) | | Available | | | Pricing |
| ($ in millions) | December 31, 2020 |
| 2015 Agreement | $ | 250 | | | $ | 50 | | | $ | 12 | | | $ | 238 | | | — | % | | LIBOR + 1.000% | or ABR + 0.00% |
(1)(4)Included $12 million in LOCs at a rate of 1.00% per annum issued in January 2020 pursuantTEP plans to TEP taking ownership of Oso Grande under the BTA.
As of February 10, 2022, there was $220 million available underamend the 2021 Credit Agreement.Agreement to provide for the transition to SOFR-based borrowings before the end of the second quarter of 2023.
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 | | 2021 | | 2020 |
| Lease Assets | | | | | |
| | | | | |
| | | | | |
| Regulatory and Other Assets, Other | Operating | | $ | 7 | | | $ | 8 | |
| Lease Liabilities | | | | | |
| | | | | |
| | | | | |
| Current Liabilities, Other | Operating | | 1 | | | 1 | |
| Regulatory and Other Liabilities, Other | Operating | | 6 | | | 7 | |
OPERATING LEASES
TEP leases office facilities, land, rail cars, and communication tower space with remaining terms of one to 20 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.
LEASE COST
The following table presents the components of TEP’s lease costs: | | | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| (in millions) | 2021 | | 2020 | | 2019 | | |
| Finance | | | | | | | |
Amortization of Leased Assets (1)(2) | $ | — | | | $ | 10 | | | $ | 13 | | | |
Interest on Lease Liabilities (3) | — | | | 2 | | | 13 | | | |
| Operating | 1 | | | 1 | | | 1 | | | |
Variable (4) | 4 | | | 2 | | | 16 | | | |
| Short Term | 2 | | | 1 | | | 1 | | | |
| Total Lease Cost | $ | 7 | | | $ | 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. See Note 3 for additional information about TEP's purchase of Springerville Common Facilities.
(2)TEP entered into a tolling PPA to purchase and receive capacity, power, and ancillary services from Gila River Unit 2, which was accounted for as a finance lease. In 2019, TEP deferred $6 million of amortization in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on PPFAC recovery of TEP's fixed capacity payment. TEP purchased Gila River Unit 2 in December 2019.
(3)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.
(4)Variable lease cost is primarily comprised of battery storage with variable payments contingent on performance. In April 2021, a 20-year renewable PPA, accompanied by battery storage, achieved commercial operation. See Note 9 for additional information about TEP's renewable PPAs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
MATURITY ANALYSIS OF LEASE LIABILITIES
As of December 31, 2021, TEP's future minimum lease payments, excluding payments to lessors for variable costs, follow: | | | | | | | | |
| (in millions) | | | Operating Leases | |
| 2022 | | | $ | 1 | | |
| 2023 | | | 1 | | |
| 2024 | | | 1 | | |
| 2025 | | | 1 | | |
| 2026 | | | 1 | | |
| Thereafter | | | 3 | | |
| Total Lease Payments | | | 8 | | |
| Less Imputed Interest | | | 1 | | |
| Total Lease Obligations | | | 7 | | |
| Less Current Portion | | | 1 | | |
| Total Non-Current Lease Obligations | | | $ | 6 | | |
LEASE TERMS AND DISCOUNT RATES
The following table presents TEP's lease terms and discount rates related to its leases: | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| Weighted-Average Remaining Lease Term (years) | | | |
| | | |
| Operating Leases | 11 | | 11 |
| Weighted-Average Discount Rate | | | |
| | | |
| Operating Leases | 3.9 | % | | 3.9 | % |
LEASE CASH FLOWS
The following table presents cash paid for amounts included in the measurement of lease liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Years Ended December 31, | | | | | | |
| (in millions) | 2021 | | 2020 | | 2019 | | | | | | | | |
| Operating Cash Flows used for Finance Leases | $ | — | | | $ | 1 | | | $ | 13 | | | | | | | | | |
| Operating Cash Flows used for Operating Leases | 1 | | | 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 oftwo to 21 years. Most leases include 1 or more options to renew with renewal terms that may extend a lease term for up to three years.
TEP's operating lease income was $1 million in each of 2021, 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, 2021, are $1 million or less in each year from 2022 through 2026 and $2 million thereafter.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 9.8. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As of December 31, 2021,2022, TEP had the following commitments: | | (in millions) | (in millions) | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total | (in millions) | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | Thereafter | | Total |
| Minimum Purchase Commitments | Minimum Purchase Commitments | | | | | | | | | | | | | | Minimum Purchase Commitments | | | | | | | | | | | | | |
| Fuel, Including Transportation | Fuel, Including Transportation | $ | 83 | | | $ | 74 | | | $ | 36 | | | $ | 28 | | | $ | 25 | | | $ | 144 | | | $ | 390 | | Fuel, Including Transportation | $ | 107 | | | $ | 57 | | | $ | 48 | | | $ | 45 | | | $ | 44 | | | $ | 176 | | | $ | 477 | |
| Purchased Power | Purchased Power | 47 | | | 47 | | | — | | | — | | | — | | | — | | | 94 | | Purchased Power | 78 | | | 16 | | | — | | | — | | | — | | | — | | | 94 | |
| Transmission | Transmission | 31 | | | 20 | | | 15 | | | 13 | | | 5 | | | 4 | | | 88 | | Transmission | 28 | | | 23 | | | 21 | | | 4 | | | 1 | | | 3 | | | 80 | |
| Purchase Commitments | Purchase Commitments | | Purchase Commitments | |
| Renewable Power Purchase Agreements | Renewable Power Purchase Agreements | 80 | | | 80 | | | 79 | | | 79 | | | 79 | | | 847 | | | 1,244 | | Renewable Power Purchase Agreements | 80 | | | 80 | | | 79 | | | 79 | | | 79 | | | 768 | | | 1,165 | |
| RES Performance-Based Incentives | RES Performance-Based Incentives | 7 | | | 7 | | | 7 | | | 5 | | | 5 | | | 23 | | | 54 | | RES Performance-Based Incentives | 7 | | | 7 | | | 5 | | | 4 | | | 4 | | | 19 | | | 46 | |
| Total Commitments | Total Commitments | $ | 248 | | | $ | 228 | | | $ | 137 | | | $ | 125 | | | $ | 114 | | | $ | 1,018 | | | $ | 1,870 | | Total Commitments | $ | 300 | | | $ | 183 | | | $ | 153 | | | $ | 132 | | | $ | 128 | | | $ | 966 | | | $ | 1,862 | |
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 2023 and 2031. In 2022, TEP amended and extended its existing coal sales agreement for the supply of coal for Springerville Unit 1 through 2027 and Unit 2 through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs.
In 2021, TEP entered into natural gas commodity purchase agreements at market prices that expire through the fourth quarter2023. Certain of 2023.these contracts are at a fixed price per MMBtu 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, 2021.2022.
TEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. In 2022, TEP extended an agreement for gas transportation to Luna through 2032. These agreements expire in various years between 20222023 and 2040.
TEP has related party agreements for natural gas supply with UNS Electric through 2023. UNS Electric will pay TEP monthly charges equal to 50% of TEP's related monthly natural gas cost. Natural gas is supplied as needed to meet UNS Electric’s load requirements. TEP's commitment does not reflect any reduction for the subsequent sale of natural gas. See Note 6 for more information on related party transactions.
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 2021, general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the third quarter of 2024. Certain of these contracts are at a fixed price per MW and others are indexed to market prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2022.
TEP entered intohas a tolling PPAsPPA to purchase and receive up to 300 MW of capacity, power, and ancillary services from June 15 through October 15, in 2022 and 2023. TEP will pay monthly capacity charges and variable power charges.
In 2021, TEP also entered intohas a tolling PPAsPPA with UNS Electric to sell and deliver up to 150 MW of capacity, power, and ancillary services over the same periods.period. UNS Electric will pay TEP monthly capacity charges equal to 50% of TEP's monthly capacity charges and variable power charges. TEP's commitment does not reflect any reduction for the subsequent sale of capacity. See Note 6 for more information on related party transactions.
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 20222023 and 2030.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Purchase Commitments
Renewable Power Purchase Agreements
TEP enters into long-term renewable PPAs, which require TEP to purchase 100% of certain renewable energy generation facilities' output and RECs associated with the output delivered once commercial operation status is achieved. In 2021, two PPA facilities and the associated battery storage achieved commercial operation. The PPAs expire in April 2041 and December 2051. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2051.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RES Performance-Based Incentives
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 20222023 and 2034.
CONTINGENCIES
Legal Matters
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.
Mine Reclamation at Generation Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreements’ terms.agreement. TEP’s PPFAC allows the Company to pass through to retail customers final mine reclamation costs, as a component of fuel costs, to retail customers.costs. Therefore, TEP defers these expenses until recovered from customers by increasing therecording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements andagreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.
TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimatedTEP's share of final mine reclamation costs at both minesFour Corners is $44$8 million upon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the related coal supply agreements, which expire inagreement on June 30, 2022. As of December 31, 2022, and 2031, respectively. An aggregate liability balance related to San Juan and Four CornersTEP's remaining final mine reclamation of $40 million as of December 31, 2021 and 2020,liability at San Juan was recorded in Other on the Consolidated Balance Sheets.$32 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. SeeFor additional information see Note 1, Restricted Cash, and Note 2 for additional information3, Plant in Service.
TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation costs.totaled $37 million and $40 million as of December 31, 2022 and 2021, respectively, and was recorded in Other on the Consolidated Balance Sheets.
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,at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. 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, thereThere is no maximum potential amount of future payments TEP could be required to make under the guarantees.Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of December 31, 2021,2022, there have been no such payment defaults under anyeither of the participation agreements.
The Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, the non-defaulting participants would seek financial recovery directly from the defaulting party.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Environmental Matters
TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.
Broadway-Pantano Site
The Water Quality Assurance Revolving Fund (WQARF)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).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, theseThese landfills were in operation from 1959 to 1972 and 1953 and 1973.to 1962, respectively. 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 10.9. EMPLOYEE BENEFITS PLANS
PENSION BENEFIT PLANS
TEP has 3three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. NaNTwo of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under IRS regulations. TEP also maintains a SERP for executive management.
OTHER POSTRETIREMENT BENEFITS PLAN
TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.
TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $2 million in 2022, $3 million in 2021, and $1 million in 2020 and 2019.2020. 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 | | Pension Benefits | | Other Postretirement Benefits |
| | December 31, | | December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2021 | | 2020 | (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Regulatory Assets | Regulatory Assets | $ | 126 | | | $ | 150 | | | $ | 2 | | | $ | 16 | | Regulatory Assets | $ | 90 | | | $ | 126 | | | $ | — | | | $ | 2 | |
| | Regulatory Liabilities | | Regulatory Liabilities | — | | | — | | | (8) | | | — | |
| Regulatory and Other Assets—Other | | Regulatory and Other Assets—Other | 8 | | | — | | | — | | | — | |
| Accrued Employee Expenses | Accrued Employee Expenses | (1) | | | (1) | | | (3) | | | (3) | | Accrued Employee Expenses | (1) | | | (1) | | | (2) | | | (3) | |
| Pension and Other Postretirement Benefits | Pension and Other Postretirement Benefits | (61) | | | (91) | | | (59) | | | (72) | | Pension and Other Postretirement Benefits | (20) | | | (61) | | | (49) | | | (59) | |
| Accumulated Other Comprehensive Loss, SERP | 13 | | | 14 | | | — | | | — | | |
| Accumulated Other Comprehensive Loss | | Accumulated Other Comprehensive Loss | 4 | | | 13 | | | — | | | — | |
| Net Amount Recognized | Net Amount Recognized | $ | 77 | | | $ | 72 | | | $ | (60) | | | $ | (59) | | Net Amount Recognized | $ | 81 | | | $ | 77 | | | $ | (59) | | | $ | (60) | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
OBLIGATIONS AND FUNDED STATUS
The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 20212022 and 2020.2021. The table below presents the status of all of TEP’sTEP pension and other postretirement benefit plans. | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| Years Ended December 31, |
| (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Change in Benefit Obligation | | | | | | | |
| Beginning of Period | $ | 600 | | | $ | 606 | | | $ | 90 | | | $ | 99 | |
| Actuarial Gain | (176) | | | (6) | | | (17) | | | (12) | |
| Interest Cost | 16 | | | 14 | | | 2 | | | 2 | |
| Service Cost | 21 | | | 20 | | | 5 | | | 6 | |
| Benefits Paid | (35) | | | (34) | | | (6) | | | (5) | |
Plan Amendments (1) | 1 | | | — | | | — | | | — | |
Settlements (2) | (16) | | | — | | | — | | | — | |
End of Period (3) | 411 | | | 600 | | | 74 | | | 90 | |
| Change in Fair Value of Plan Assets | | | | | | | |
| Beginning of Period | 538 | | | 514 | | | 28 | | | 24 | |
| Actual Return on Plan Assets | (101) | | | 43 | | | (4) | | | 3 | |
| Benefits Paid | (34) | | | (32) | | | (3) | | | (2) | |
Employer Contributions (4) | 11 | | | 13 | | | 2 | | | 3 | |
Settlements (2) | (16) | | | — | | | — | | | — | |
End of Period (5) | 398 | | | 538 | | | 23 | | | 28 | |
| Funded Status at End of Period | $ | (13) | | | $ | (62) | | | $ | (51) | | | $ | (62) | |
(1)Employees promoted to officer become eligible for SERP benefits based in part on their service prior to officer promotion. These prior service costs are accounted for in this table as a plan amendment.
(2)Represents the aggregate lump-sum benefit payments for plans that exceeded the threshold of service plus interest costs. The change is due to an increase in retiring employees opting to receive their benefits as a lump-sum as a result of a rise in interest rates.
(3)The decrease in pension and other postretirement benefit obligations was primarily due to an increase in the discount rate.
(4)TEP expects to contribute $7 million to the pension plans and less than $1 million to the VEBA trust in 2023.
(5)The decrease in pension and other postretirement benefit plan assets was primarily due to negative equity and fixed income returns.
One pension plan had a projected benefit obligation in excess of plan assets as of December 31, 2022, compared to all three as of December 31, 2021. This was due to an increase in discount rates only partially offset by negative equity and fixed income returns. For plans with projected benefit obligations in excess of plan assets, total projected benefit obligations and plan assets were $21 million and none, respectively, as of December 31, 2022, and $600 million and $538 million, respectively, as of December 31, 2021.
The other postretirement benefits plan had an accumulated postretirement benefit obligation in excess of the fair value of plan assets as of December 31, 2022 and 2021.
The accumulated benefit obligation aggregated for all pension plans was $373 million and $538 million as of December 31, 2022 and 2021, respectively. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2022 and 2021. The following table includes information for the pension plan with an accumulated benefit obligation in excess of pension plan assets: | | | | | | | | | | | |
| December 31, |
| (in millions) | 2022 | | 2021 |
| Accumulated Benefit Obligation | $ | 19 | | | $ | 26 | |
| Fair Value of Plan Assets | — | | | — | |
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) | 2021 | | 2020 | | 2021 | | 2020 |
| Change in Benefit Obligation | | | | | | | |
| Beginning of Period | $ | 606 | | | $ | 525 | | | $ | 99 | | | $ | 79 | |
| Actuarial (Gain) Loss | (6) | | | 76 | | | (12) | | | 18 | |
| Interest Cost | 14 | | | 16 | | | 2 | | | 3 | |
| Service Cost | 20 | | | 16 | | | 6 | | | 4 | |
| Benefits Paid | (34) | | | (27) | | | (5) | | | (5) | |
| | | | | | | |
| End of Period | 600 | | | 606 | | | 90 | | | 99 | |
| Change in Fair Value of Plan Assets | | | | | | | |
| Beginning of Period | 514 | | | 446 | | | 24 | | | 21 | |
| Actual Return on Plan Assets | 43 | | | 78 | | | 3 | | | 3 | |
| Benefits Paid | (32) | | | (26) | | | (2) | | | (5) | |
Employer Contributions (1) | 13 | | | 16 | | | 3 | | | 5 | |
End of Period (2) | 538 | | | 514 | | | 28 | | | 24 | |
| Funded Status at End of Period | $ | (62) | | | $ | (92) | | | $ | (62) | | | $ | (75) | |
(1)TEP expects to contribute $11 million to the pension plans and less than $1 million to the VEBA trust in 2022.
(2)The increase in pension benefit plan assets was primarily due to positive equity returns.
The following table provides the components of TEP’s regulatory assets, regulatory liabilities, and accumulated other comprehensive lossAOCL 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) | 2021 | | 2020 | | 2021 | | 2020 |
| Net Loss | $ | 139 | | | $ | 164 | | | $ | 4 | | | $ | 18 | |
| Prior Service Cost (Benefit) | — | | | 1 | | | (2) | | | (2) | |
The accumulated benefit obligations aggregated for all pension plans as of December 31, 2021, was $538 million. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2021, compared to all three as of December 31, 2020. This was due to an increase in discount rates and positive equity returns. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: | | | | | | | | | | | |
| December 31, |
| (in millions) | 2021 | | 2020 |
| Accumulated Benefit Obligation | $ | 26 | | | $ | 545 | |
| Fair Value of Plan Assets | — | | | 514 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| December 31, |
| (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Net Loss (Gain) | $ | 93 | | | $ | 139 | | | $ | (7) | | | $ | 4 | |
| Prior Service Cost (Benefit) | 1 | | | — | | | (1) | | | (2) | |
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 | | Pension Benefits | | Other Postretirement Benefits |
| | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Service Cost | Service Cost | $ | 20 | | | $ | 16 | | | $ | 13 | | | $ | 6 | | | $ | 4 | | | $ | 4 | | Service Cost | $ | 21 | | | $ | 20 | | | $ | 16 | | | $ | 5 | | | $ | 6 | | | $ | 4 | |
Non-Service Cost | Non-Service Cost | | Non-Service Cost | |
| Interest Cost | Interest Cost | 14 | | | 16 | | | 18 | | | 2 | | | 3 | | | 3 | | Interest Cost | 16 | | | 14 | | | 16 | | | 2 | | | 2 | | | 3 | |
| Expected Return on Plan Assets | Expected Return on Plan Assets | (34) | | | (30) | | | (26) | | | (2) | | | (2) | | | (2) | | Expected Return on Plan Assets | (37) | | | (34) | | | (30) | | | (1) | | | (2) | | | (2) | |
| | Amortization of Net (Gain) Loss | 9 | | | 8 | | | 8 | | | 1 | | | — | | | — | | |
| Prior Service Benefit Amortization | | Prior Service Benefit Amortization | — | | | — | | | — | | | (1) | | | — | | | — | |
| Amortization of Net Loss | | Amortization of Net Loss | 7 | | | 9 | | | 8 | | | — | | | 1 | | | — | |
| Effect of Settlement | | Effect of Settlement | 3 | | | — | | | — | | | — | | | — | | | — | |
| Net Periodic Benefit Cost | Net Periodic Benefit Cost | $ | 9 | | | $ | 10 | | | $ | 13 | | | $ | 7 | | | $ | 5 | | | $ | 5 | | Net Periodic Benefit Cost | $ | 10 | | | $ | 9 | | | $ | 10 | | | $ | 5 | | | $ | 7 | | | $ | 5 | |
The non-service components of net periodic benefit cost are primarily included in Other, Net on the Consolidated Statements of Income. In 2022, $3 million of the effect of settlement was deferred as a regulatory asset and recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets. TEP capitalized 22%21% of service cost as a cost of construction in 2022, and 22% in each of 2021 and 2020, and 21% in 2019.2020.
The changes in plan assets and benefit obligations recognized as regulatory assets, regulatory liabilities, or in AOCIAOCL were as follows: | | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
| | Regulatory Asset | | AOCI | | Regulatory Asset | | Regulatory Asset | | AOCL | | Regulatory Asset/Liability |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Current Year Actuarial (Gain) Loss | Current Year Actuarial (Gain) Loss | $ | (16) | | | $ | 23 | | | $ | 16 | | | $ | — | | | $ | 5 | | | $ | 4 | | | $ | (13) | | | $ | 17 | | | $ | 1 | | Current Year Actuarial (Gain) Loss | $ | (27) | | | $ | (16) | | | $ | 23 | | | $ | (9) | | | $ | — | | | $ | 5 | | | $ | (11) | | | $ | (13) | | | $ | 17 | |
| Prior Service Benefit Amortization | | Prior Service Benefit Amortization | — | | | — | | | — | | | — | | | — | | | — | | | 1 | | | — | | | — | |
| Amortization of Net Loss | Amortization of Net Loss | (8) | | | (8) | | | (8) | | | (1) | | | (1) | | | (1) | | | (1) | | | — | | | — | | Amortization of Net Loss | (6) | | | (8) | | | (8) | | | (1) | | | (1) | | | (1) | | | — | | | (1) | | | — | |
| Prior Service (Credit) Cost | — | | | — | | | — | | | — | | | — | | | 1 | | | — | | | — | | | — | | |
| Prior Service Cost | | Prior Service Cost | — | | | — | | | — | | | 1 | | | — | | | — | | | — | | | — | | | — | |
| Effect of Settlement | | Effect of Settlement | (3) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total Recognized (Gain) Loss | Total Recognized (Gain) Loss | $ | (24) | | | $ | 15 | | | $ | 8 | | | $ | (1) | | | $ | 4 | | | $ | 4 | | | $ | (14) | | | $ | 17 | | | $ | 1 | | Total Recognized (Gain) Loss | $ | (36) | | | $ | (24) | | | $ | 15 | | | $ | (9) | | | $ | (1) | | | $ | 4 | | | $ | (10) | | | $ | (14) | | | $ | 17 | |
For all pension plans, TEP amortizes prior service costs and benefits on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.
Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard toregarding 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 the25th 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 |
| 2021 | | 2020 | | 2021 | | 2020 |
| Discount Rate | 3.2% | | 2.9% | | 3.0% | | 2.6% |
| 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 |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| Discount Rate, Service Cost | 3.3% | | 3.8% | | 4.7% | | 2.9% | | 3.5% | | 4.5% |
| Discount Rate, Interest Cost | 2.3% | | 3.1% | | 4.2% | | 1.9% | | 2.9% | | 4.0% |
| Rate of Compensation Increase | 2.8% | | 2.8% | | 2.8% | | N/A | | N/A | | N/A |
| Expected Return on Plan Assets | 6.8% | | 6.8% | | 7.0% | | 7.0% | | 7.0% | | 7.0% |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table includes the weighted average assumptions used to determine benefit obligations: | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| 2022 | | 2021 | | 2022 | | 2021 |
| Discount Rate | 5.7% | | 3.2% | | 5.6% | | 3.0% |
| Rate of Compensation Increase | 2.9% | | 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 |
| 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Discount Rate, Service Cost | 3.4% | | 3.3% | | 3.8% | | 3.2% | | 2.9% | | 3.5% |
| Discount Rate, Interest Cost | 2.7% | | 2.3% | | 3.1% | | 2.5% | | 1.9% | | 2.9% |
| Rate of Compensation Increase | 2.8% | | 2.8% | | 2.8% | | N/A | | N/A | | N/A |
| Expected Return on Plan Assets | 7.0% | | 6.8% | | 6.8% | | 7.0% | | 7.0% | | 7.0% |
Healthcare cost trend rates are assumed to decrease gradually from Next Yearnext year to the year the ultimate rate is reached: | | | December 31, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Next Year (Pre-65) | Next Year (Pre-65) | 6.5% | | 6.1% | Next Year (Pre-65) | 7.0% | | 6.5% |
| Next Year (Post-65) | Next Year (Post-65) | 5.5% | | 7.1% | Next Year (Post-65) | 6.0% | | 5.5% |
| Ultimate Rate Assumed (Pre-65 and Post-65) | Ultimate Rate Assumed (Pre-65 and Post-65) | 4.5% | | 4.5% | Ultimate Rate Assumed (Pre-65 and Post-65) | 4.5% | | 4.5% |
| Year Ultimate Rate is Reached (Pre-65) | Year Ultimate Rate is Reached (Pre-65) | 2031 | | 2037 | Year Ultimate Rate is Reached (Pre-65) | 2032 | | 2031 |
| Year Ultimate Rate is Reached (Post-65) | Year Ultimate Rate is Reached (Post-65) | 2027 | | 2037 | Year Ultimate Rate is Reached (Post-65) | 2028 | | 2027 |
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 | | Pension | | Other Postretirement Benefits |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Asset Category | Asset Category | | | | | | | | Asset Category | | | | | | | |
| Equity Securities | Equity Securities | 54 | % | | 47 | % | | 63 | % | | 63 | % | Equity Securities | 53 | % | | 54 | % | | 61 | % | | 63 | % |
| Fixed Income Securities | Fixed Income Securities | 40 | % | | 45 | % | | 35 | % | | 35 | % | Fixed Income Securities | 39 | % | | 40 | % | | 38 | % | | 35 | % |
| Real Estate | Real Estate | 5 | % | | 7 | % | | — | % | | — | % | Real Estate | 7 | % | | 5 | % | | — | % | | — | % |
| Other | Other | 1 | % | | 1 | % | | 2 | % | | 2 | % | Other | 1 | % | | 1 | % | | 1 | % | | 2 | % |
| Total | Total | 100 | % | | 100 | % | | 100 | % | | 100 | % | Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
As of December 31, 2022, the fair value of VEBA trust assets was $23 million, of which $9 million were fixed income investments and $14 million were equities. As of December 31, 2021, the fair value of VEBA trust assets was $28 million, of which $10 million were fixed income investments and $18 million were equities. 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. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: | | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| (in millions) | (in millions) | December 31, 2021 | (in millions) | December 31, 2022 |
| Asset Category | Asset Category | | Asset Category | |
| Cash Equivalents | $ | 2 | | | $ | — | | | $ | — | | | $ | 2 | | |
| | Equity Securities: | Equity Securities: | | Equity Securities: | |
| United States Large Cap | United States Large Cap | — | | | 77 | | | — | | | 77 | | United States Large Cap | — | | | 61 | | | — | | | 61 | |
| United States Small Cap | United States Small Cap | — | | | 28 | | | — | | | 28 | | United States Small Cap | — | | | 23 | | | — | | | 23 | |
| Non-United States | Non-United States | — | | | 105 | | | — | | | 105 | | Non-United States | — | | | 66 | | | — | | | 66 | |
| Global | Global | — | | | 83 | | | — | | | 83 | | Global | — | | | 61 | | | — | | | 61 | |
| Fixed Income | Fixed Income | — | | | 213 | | | — | | | 213 | | Fixed Income | — | | | 154 | | | — | | | 154 | |
| Real Estate | Real Estate | — | | | — | | | 26 | | | 26 | | Real Estate | — | | | — | | | 30 | | | 30 | |
| Private Equity | Private Equity | — | | | — | | | 4 | | | 4 | | Private Equity | — | | | — | | | 3 | | | 3 | |
| Total | Total | $ | 2 | | | $ | 506 | | | $ | 30 | | | $ | 538 | | Total | $ | — | | | $ | 365 | | | $ | 33 | | | $ | 398 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| | (in millions) | (in millions) | December 31, 2020 | (in millions) | December 31, 2021 |
| Asset Category | Asset Category | | Asset Category | |
| | Cash Equivalents | | Cash Equivalents | $ | 2 | | | $ | — | | | $ | — | | | $ | 2 | |
| Equity Securities: | Equity Securities: | | Equity Securities: | |
| United States Large Cap | United States Large Cap | $ | — | | | $ | 65 | | | $ | — | | | $ | 65 | | United States Large Cap | — | | | 77 | | | — | | | 77 | |
| United States Small Cap | United States Small Cap | — | | | 25 | | | — | | | 25 | | United States Small Cap | — | | | 28 | | | — | | | 28 | |
| Non-United States | Non-United States | — | | | 95 | | | — | | | 95 | | Non-United States | — | | | 105 | | | — | | | 105 | |
| Global | Global | — | | | 59 | | | — | | | 59 | | Global | — | | | 83 | | | — | | | 83 | |
| Fixed Income | Fixed Income | — | | | 231 | | | — | | | 231 | | Fixed Income | — | | | 213 | | | — | | | 213 | |
| Real Estate | Real Estate | — | | | 12 | | | 23 | | | 35 | | Real Estate | — | | | — | | | 26 | | | 26 | |
| Private Equity | Private Equity | — | | | — | | | 4 | | | 4 | | Private Equity | — | | | — | | | 4 | | | 4 | |
| Total | Total | $ | — | | | $ | 487 | | | $ | 27 | | | $ | 514 | | Total | $ | 2 | | | $ | 506 | | | $ | 30 | | | $ | 538 | |
•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 similarcomparable properties.
•Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. | | (in millions) | (in millions) | Private Equity | | Real Estate | | Total | (in millions) | Private Equity | | Real Estate | | Total |
| 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 | Balance as of December 31, 2020 | 4 | | | 23 | | | 27 | | Balance as of December 31, 2020 | $ | 4 | | | $ | 23 | | | $ | 27 | |
| Actual Return on Plan Assets: | Actual Return on Plan Assets: | | Actual Return on Plan Assets: | |
| Assets Held at Reporting Date | Assets Held at Reporting Date | 2 | | | 3 | | | 5 | | Assets Held at Reporting Date | 2 | | | 3 | | | 5 | |
| Purchases, Sales, and Settlements | Purchases, Sales, and Settlements | (2) | | | — | | | (2) | | Purchases, Sales, and Settlements | (2) | | | — | | | (2) | |
| Balance as of December 31, 2021 | Balance as of December 31, 2021 | $ | 4 | | | $ | 26 | | | $ | 30 | | Balance as of December 31, 2021 | 4 | | | 26 | | | 30 | |
| Actual Return on Plan Assets: | | Actual Return on Plan Assets: | |
| Assets Held at Reporting Date | | Assets Held at Reporting Date | — | | | 4 | | | 4 | |
| Purchases, Sales, and Settlements | | Purchases, Sales, and Settlements | (1) | | | — | | | (1) | |
| Balance as of December 31, 2022 | | Balance as of December 31, 2022 | $ | 3 | | | $ | 30 | | | $ | 33 | |
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 ofconsidering the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status;
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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.portfolio. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
Relationship between Plan Assets and Benefit Obligations
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data but will be no less frequent than annually via actuarial valuation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Target Allocation Percentages
The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced: | | | Pension | | Other Postretirement Benefits | | Pension | | Other Postretirement Benefits |
| | December 31, 2021 | | December 31, 2022 |
| Cash/Treasury Bills | Cash/Treasury Bills | —% | | 2% | Cash/Treasury Bills | —% | | 1% |
| Equity Securities: | Equity Securities: | | Equity Securities: | |
| United States Large Cap | United States Large Cap | 13% | | 39% | United States Large Cap | 16% | | 25% |
| United States Mid Cap | | United States Mid Cap | —% | | 8% |
| United States Small Cap | United States Small Cap | 5% | | 5% | United States Small Cap | 6% | | 4% |
| Non-United States Developed | Non-United States Developed | —% | | 7% | Non-United States Developed | —% | | 15% |
| Non-United States Emerging | Non-United States Emerging | —% | | 9% | Non-United States Emerging | —% | | 8% |
| Global Equity | Global Equity | 32% | | —% | Global Equity | 28% | | —% |
| Global Infrastructure | Global Infrastructure | 3% | | —% | Global Infrastructure | 3% | | —% |
| Fixed Income | Fixed Income | 40% | | 38% | Fixed Income | 40% | | 39% |
| Real Estate | Real Estate | 6% | | —% | Real Estate | 6% | | —% |
| Private Equity | Private Equity | 1% | | —% | Private Equity | 1% | | —% |
| Total | Total | 100% | | 100% | 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’third-party funds.
ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate: | | (in millions) | (in millions) | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027-2031 | (in millions) | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2028-2032 |
| Pension Benefits | Pension Benefits | $ | 28 | | | $ | 29 | | | $ | 29 | | | $ | 29 | | | $ | 30 | | | $ | 158 | | Pension Benefits | $ | 25 | | | $ | 26 | | | $ | 26 | | | $ | 27 | | | $ | 27 | | | $ | 149 | |
| Other Postretirement Benefits | Other Postretirement Benefits | 5 | | | 5 | | | 5 | | | 6 | | | 5 | | | 26 | | Other Postretirement Benefits | 6 | | | 6 | | | 6 | | | 6 | | | 5 | | | 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 $7 million in each of 2022 and 2021, and $6 million in 2020 and 2019.2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 11.10. SHARE-BASED COMPENSATION
2020 FORTIS RESTRICTED STOCK UNIT PLAN
The Fortis Board of Directors ratified the 2020 Restricted Stock Unit Plan (2020 Plan) effective January 2020. Under the 2020 Plan, executive officers of Fortis and its subsidiaries may be granted time-based RSUs annually, which may be settled in cash or shares. Each RSU granted is valued based on 1one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table represents RSUs awarded by Fortis for UNS Energy: | | | | | | | | | | | |
| 2021 | | 2020 |
| RSUs | 20,794 | | | 15,751 | |
| | | | | | | | | | | |
| 2022 | | 2021 |
| RSUs | 17,996 | | | 20,794 | |
The awards are initially classified as liability awards because: (i) executive officers have the option to elect the cash or share settlement feature; and (ii) this election is contingent on an event within the executive officers' control. The liability awards may be reclassified as equity awards if the executive officers elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $2 million and $1 million as of December 31, 20212022 and 2020, respectively.2021.
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 no compensation expense in 2022 or 2021 and $1 million in 2020 based on its share of Fortis' compensation expense.
2015 SHARE UNIT PLAN
The Human Resources and Governance Committee of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (2015 Plan) effective January 2015. Under the 2015 Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of PSUs and RSUs annually. Each PSU and RSU granted is valued based on 1one 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: | | | 2021 | | 2020 | | 2019 | | 2022 | | 2021 | | 2020 |
| PSUs | PSUs | 44,931 | | | 35,328 | | | 66,978 | | PSUs | 40,793 | | | 44,931 | | | 35,328 | |
RSUs (1) | RSUs (1) | 2,401 | | | 1,918 | | | 33,489 | | RSUs (1) | 2,409 | | | 2,401 | | | 1,918 | |
(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 $9$4 million and $10$9 million as of December 31, 20212022 and 2020,2021, 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 $2 million in 2022, $4 million in 2021, and $3 million in 2020 and $4 million in 2019 based on its share of UNS Energy's compensation expense.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 12.11. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Interest Paid, Net of Amounts Capitalized | Interest Paid, Net of Amounts Capitalized | $ | 76 | | | $ | 76 | | | $ | 80 | | Interest Paid, Net of Amounts Capitalized | $ | 80 | | | $ | 76 | | | $ | 76 | |
Income Tax Refunds (1) | Income Tax Refunds (1) | — | | | (14) | | | (14) | | Income Tax Refunds (1) | — | | | — | | | (14) | |
(1)TEP received refunds of AMT credit carryforwards in 2020 and 2019. See Note 1413 for additional information regarding AMT.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Accrued Capital Expenditures | Accrued Capital Expenditures | $ | 38 | | | $ | 26 | | | $ | 40 | | Accrued Capital Expenditures | $ | 26 | | | $ | 38 | | | $ | 26 | |
Asset Retirement Obligations Increase (Decrease) (1) | 34 | | | (12) | | | 26 | | |
| | Renewable Energy Credits | Renewable Energy Credits | 3 | | | 3 | | | 3 | | Renewable Energy Credits | 3 | | | 3 | | | 3 | |
Operating Leases (2) | Operating Leases (2) | — | | | 1 | | | 8 | | Operating Leases (2) | — | | | — | | | 1 | |
| | Finance Leases | — | | | — | | | 67 | | |
| Net Cost of Removal Increase (Decrease) (3) | (41) | | | (34) | | | (10) | | |
| Asset Retirement Obligations Increase (Decrease) (1) | | Asset Retirement Obligations Increase (Decrease) (1) | (30) | | | 34 | | | (12) | |
Net Cost of Removal Increase (Decrease) (2) | | Net Cost of Removal Increase (Decrease) (2) | (49) | | | (41) | | | (34) | |
(1)The non-cash additionsIn 2021, primarily represents a new obligation related to AROs and related capitalized assets represent a revisionOso Grande. In 2022, primarily represents the retirement of estimatedthe San Juan asset retirement cost due to changes in timing and amount of expected future cash flows.asset.
(2)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.
(3)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. See Note 1 for additional informationIn 2021, TEP transferred a portion of the Net Cost of Removal recorded in Regulatory Liabilities to Accumulated Depreciation and Amortization on the Consolidated Balance Sheets to reflect the impact of revised depreciation rates. In 2022, TEP reclassified a portion of the Net Cost of Removal related to new depreciation rates approved as partSan Juan to the unrecovered book value of the 2020 Rate Order.retiring asset.
NOTE 13.12. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.
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 | | Level 1 | | Level 2 | | | Total |
| (in millions) | (in millions) | December 31, 2021 | (in millions) | December 31, 2022 |
| Assets | Assets | | Assets | |
| Restricted Cash (1) | Restricted Cash (1) | $ | 23 | | | $ | — | | | | $ | 23 | | Restricted Cash (1) | $ | 35 | | | $ | — | | | | $ | 35 | |
Energy Derivative Contracts, Regulatory Recovery (2) | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | 30 | | | | 30 | | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | 100 | | | | 100 | |
Energy Derivative Contracts, No Regulatory Recovery (2) | Energy Derivative Contracts, No Regulatory Recovery (2) | — | | | 4 | | | | 4 | | Energy Derivative Contracts, No Regulatory Recovery (2) | — | | | 4 | | | | 4 | |
| Total Assets | Total Assets | 23 | | | 34 | | | | 57 | | Total Assets | 35 | | | 104 | | | | 139 | |
| Liabilities | Liabilities | | | | | | | Liabilities | | | | | | |
Energy Derivative Contracts, Regulatory Recovery (2) | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | (20) | | | | (20) | | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | (18) | | | | (18) | |
| | Total Liabilities | Total Liabilities | — | | | (20) | | | | (20) | | Total Liabilities | — | | | (18) | | | | (18) | |
| Total Assets (Liabilities), Net | Total Assets (Liabilities), Net | $ | 23 | | | $ | 14 | | | | $ | 37 | | Total Assets (Liabilities), Net | $ | 35 | | | $ | 86 | | | | $ | 121 | |
| | (in millions) | (in millions) | December 31, 2020 | (in millions) | December 31, 2021 |
| Assets | Assets | | Assets | |
| Restricted Cash (1) | Restricted Cash (1) | $ | 21 | | | $ | — | | | | $ | 21 | | Restricted Cash (1) | $ | 23 | | | $ | — | | | | $ | 23 | |
Energy Derivative Contracts, Regulatory Recovery (2) | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | 14 | | | | 14 | | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | 30 | | | | 30 | |
Energy Derivative Contracts, No Regulatory Recovery (2) | Energy Derivative Contracts, No Regulatory Recovery (2) | — | | | 3 | | | | 3 | | Energy Derivative Contracts, No Regulatory Recovery (2) | — | | | 4 | | | | 4 | |
| Total Assets | Total Assets | 21 | | | 17 | | | | 38 | | Total Assets | 23 | | | 34 | | | | 57 | |
| Liabilities | Liabilities | | | | | | | Liabilities | | | | | | |
Energy Derivative Contracts, Regulatory Recovery (2) | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | (66) | | | | (66) | | Energy Derivative Contracts, Regulatory Recovery (2) | — | | | (20) | | | | (20) | |
| | Total Liabilities | Total Liabilities | — | | | (66) | | | | (66) | | Total Liabilities | — | | | (20) | | | | (20) | |
| Total Assets (Liabilities), Net | Total Assets (Liabilities), Net | $ | 21 | | | $ | (49) | | | | $ | (28) | | Total Assets (Liabilities), Net | $ | 23 | | | $ | 14 | | | | $ | 37 | |
(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 power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral: | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Amount Recognized in the Balance Sheets | | Gross Amount Not Offset in the Balance Sheets | | Net Amount |
| | Counterparty Netting of Energy Contracts | | Cash Collateral Received/Posted | |
| (in millions) | December 31, 2021 |
| Derivative Assets | | | | | | | |
| Energy Derivative Contracts | $ | 34 | | | $ | 14 | | | $ | — | | | $ | 20 | |
| Derivative Liabilities | | | | | | | |
| Energy Derivative Contracts | (20) | | | (14) | | | — | | | (6) | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | December 31, 2020 |
| Derivative Assets | | | | | | | |
| Energy Derivative Contracts | $ | 17 | | | $ | 14 | | | $ | — | | | $ | 3 | |
| Derivative Liabilities | | | | | | | |
| Energy Derivative Contracts | (66) | | | (14) | | | (7) | | | (45) | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Gross Amount Recognized in the Balance Sheets | | Gross Amount Not Offset in the Balance Sheets | | Net Amount |
| | Counterparty Netting of Energy Contracts | | Cash Collateral Received/Posted (1) | |
| (in millions) | December 31, 2022 |
| Derivative Assets | | | | | | | |
| Energy Derivative Contracts | $ | 104 | | | $ | 14 | | | $ | 14 | | | $ | 76 | |
| Derivative Liabilities | | | | | | | |
| Energy Derivative Contracts | (18) | | | (14) | | | — | | | (4) | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | December 31, 2021 |
| Derivative Assets | | | | | | | |
| Energy Derivative Contracts | $ | 34 | | | $ | 14 | | | $ | — | | | $ | 20 | |
| Derivative Liabilities | | | | | | | |
| Energy Derivative Contracts | (20) | | | (14) | | | — | | | (6) | |
| | | | | | | |
(1)TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Consolidated Balance Sheets. As of February 9, 2023, TEP held $9 million of cash received as collateral to provide credit enhancement.
DERIVATIVE INSTRUMENTS
TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers.
TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or 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, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
Unrealized Net Gain (Loss) (1) | $ | 62 | | | $ | 21 | | | $ | (45) | | |
Unrealized Net Gain (1) | | Unrealized Net Gain (1) | $ | 72 | | | $ | 62 | | | $ | 21 | |
(1)IncreaseThe change in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas.prices.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, 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, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Operating Revenues | Operating Revenues | $ | 7 | | | $ | 5 | | | $ | 6 | | Operating Revenues | $ | 11 | | | $ | 7 | | | $ | 5 | |
Derivative Volumes
As of December 31, 2021,2022, 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, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Power Contracts GWh | Power Contracts GWh | 2,617 | | | 4,143 | | Power Contracts GWh | 1,979 | | | 2,617 | |
| Gas Contracts BBtu | Gas Contracts BBtu | 112,316 | | | 111,585 | | Gas Contracts BBtu | 96,755 | | | 112,316 | |
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.
TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. In the event thatIf such credit events were to occur, TEP, or its counterparties, wouldcould 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 $86 million as of December 31, 2022, compared with $26 million as of December 31, 2021, compared with $60 million as of December 31, 2020.2021. As of December 31, 2021,2022, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on December 31, 2021,2022, TEP would have been required to post $26$86 million of collateralcollateral. As of which $21December 31, 2022, TEP had $73 million relates toin 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 | | Net Carrying Value | | Fair Value |
| | Fair Value Hierarchy | | December 31, | | Fair Value Hierarchy | | December 31, |
| (in millions) | (in millions) | | 2021 | | 2020 | | 2021 | | 2020 | (in millions) | | 2022 | | 2021 | | 2022 | | 2021 |
| Liabilities | Liabilities | | | | | | | | | | Liabilities | | | | | | | | | |
| Long-Term Debt, including Current Maturities | Long-Term Debt, including Current Maturities | Level 2 | | $ | 2,135 | | | $ | 2,064 | | | $ | 2,357 | | | $ | 2,363 | | Long-Term Debt, including Current Maturities | Level 2 | | $ | 2,265 | | | $ | 2,135 | | | $ | 1,901 | | | $ | 2,357 | |
NOTE 14.13. INCOME TAXES
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% to pre-tax income due to the following: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Federal Income Tax Expense at Statutory Rate | Federal Income Tax Expense at Statutory Rate | $ | 49 | | | $ | 49 | | | $ | 46 | | Federal Income Tax Expense at Statutory Rate | $ | 52 | | | $ | 49 | | | $ | 49 | |
| State Income Tax Expense, Net of Federal Deduction | State Income Tax Expense, Net of Federal Deduction | 9 | | | 9 | | | 9 | | State Income Tax Expense, Net of Federal Deduction | 10 | | | 9 | | | 9 | |
Federal/State Tax Credits (1) | Federal/State Tax Credits (1) | (10) | | | (3) | | | (6) | | Federal/State Tax Credits (1) | (22) | | | (10) | | | (3) | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | (3) | | | (7) | | | (3) | | Allowance for Equity Funds Used During Construction | (1) | | | (3) | | | (7) | |
| | Excess Deferred Income Taxes | Excess Deferred Income Taxes | (14) | | | (7) | | | (9) | | Excess Deferred Income Taxes | (10) | | | (14) | | | (7) | |
| Impact of AMT Sequestration | — | | | — | | | (2) | | |
| | Other | Other | 1 | | | — | | | (1) | | Other | 3 | | | 1 | | | — | |
| Total Income Tax Expense | Total Income Tax Expense | $ | 32 | | | $ | 41 | | | $ | 34 | | Total Income Tax Expense | $ | 32 | | | $ | 32 | | | $ | 41 | |
(1)In 2021, TEP realized PTC benefits of $19 million and $7 million in 2022 and 2021, respectively, related to Oso Grande being placed in service in May 2021.
Income Tax Expense included on the Consolidated Statements of Income consists of the following: | | | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | | 2019 | (in millions) | 2022 | | 2021 | | 2020 |
| Current Income Tax Expense | Current Income Tax Expense | | | | | | Current Income Tax Expense | | | | | |
| Federal | Federal | $ | (2) | | | $ | (2) | | | $ | (8) | | Federal | $ | (1) | | | $ | (2) | | | $ | (2) | |
| State | State | — | | | 1 | | | — | | State | — | | | — | | | 1 | |
| Total Current Income Tax Expense | Total Current Income Tax Expense | (2) | | | (1) | | | (8) | | Total Current Income Tax Expense | (1) | | | (2) | | | (1) | |
| Deferred Income Tax Expense | Deferred Income Tax Expense | | | | | | Deferred Income Tax Expense | | | | | |
| Federal | Federal | 27 | | | 37 | | | 41 | | Federal | 26 | | | 27 | | | 37 | |
| Federal Investment Tax Credits | Federal Investment Tax Credits | (1) | | | (1) | | | (4) | | Federal Investment Tax Credits | (1) | | | (1) | | | (1) | |
| State | State | 8 | | | 6 | | | 5 | | State | 8 | | | 8 | | | 6 | |
| Total Deferred Income Tax Expense | Total Deferred Income Tax Expense | 34 | | | 42 | | | 42 | | Total Deferred Income Tax Expense | 33 | | | 34 | | | 42 | |
| Total Income Tax Expense | Total Income Tax Expense | $ | 32 | | | $ | 41 | | | $ | 34 | | Total Income Tax Expense | $ | 32 | | | $ | 32 | | | $ | 41 | |
In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $10 million, $14 million, $7 million, and $9$7 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2022, 2021, and 2020, and 2019, respectively. As part of the 2020 Rate Order, TEP received approval of aTEP's 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 shares any changes in its EDIT amortization through the usage-based adjustor. See Note 2 for additional information regarding the 2020 Rate Order.
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, the remaining AMT credit carryforward balance of $14 million was refunded to the Company.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)(Concluded)
The significant components of deferred income tax assets and liabilities consist of the following: | | | December 31, | | December 31, |
| (in millions) | (in millions) | 2021 | | 2020 | (in millions) | 2022 | | 2021 |
| Gross Deferred Income Tax Assets | Gross Deferred Income Tax Assets | | | | Gross Deferred Income Tax Assets | | | |
| | Customer Advances and Contributions in Aid of Construction | Customer Advances and Contributions in Aid of Construction | $ | 20 | | | $ | 19 | | Customer Advances and Contributions in Aid of Construction | $ | 22 | | | $ | 20 | |
| | Other Postretirement Benefits | 15 | | | 15 | | |
| Investment Tax Credit Carryforward | 23 | | | 19 | | |
| Federal General Business Credits (1) | | Federal General Business Credits (1) | 61 | | | 32 | |
| Income Taxes Payable Through Future Rates | Income Taxes Payable Through Future Rates | 67 | | | 74 | | Income Taxes Payable Through Future Rates | 60 | | | 67 | |
| Other | Other | 93 | | | 76 | | Other | 103 | | | 99 | |
| Total Gross Deferred Income Tax Assets | Total Gross Deferred Income Tax Assets | 218 | | | 203 | | Total Gross Deferred Income Tax Assets | 246 | | | 218 | |
| | Gross Deferred Income Tax Liabilities | Gross Deferred Income Tax Liabilities | | | | Gross Deferred Income Tax Liabilities | | | |
| Plant, Net | Plant, Net | (682) | | | (639) | | Plant, Net | (735) | | | (682) | |
| PPFAC | PPFAC | (23) | | | (6) | | PPFAC | (31) | | | (23) | |
| Plant Abandonments | Plant Abandonments | (8) | | | (11) | | Plant Abandonments | (14) | | | (8) | |
| Pensions | Pensions | (18) | | | (17) | | Pensions | (20) | | | (18) | |
| Income Taxes Recoverable Through Future Rates | Income Taxes Recoverable Through Future Rates | (4) | | | (7) | | Income Taxes Recoverable Through Future Rates | (1) | | | (4) | |
| Other | Other | (32) | | | (16) | | Other | (36) | | | (32) | |
| Total Gross Deferred Income Tax Liabilities | Total Gross Deferred Income Tax Liabilities | (767) | | | (696) | | Total Gross Deferred Income Tax Liabilities | (837) | | | (767) | |
| Deferred Income Taxes, Net | Deferred Income Taxes, Net | $ | (549) | | | $ | (493) | | Deferred Income Taxes, Net | $ | (591) | | | $ | (549) | |
(1) Includes ITC and PTC carryovers.
TEP recorded no valuation allowance against all other tax credit and net operating loss carryforward deferred income tax assets as of December 31, 20212022 and 2020.2021. Management believes TEP will produce sufficient taxable income in the future to realize credit and loss carryforwards before they expire.
As of December 31, 2021,2022, TEP had the following carryforward amounts: | | | | | | | | | | | |
| ($ in millions) | Amount | | Expiring Year |
| State Net Operating Loss | $ | 1 | | | 2026 |
| State Credits | 9 | | | 2023 - 29 |
| | | |
| Investment Tax Credits | 22 | | | 2034 - 41 |
| Other Federal Credits | 8 | | | 2034 - 41 |
UNCERTAIN TAX POSITIONS
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: | | | | | | | | | | | |
| December 31, |
| (in millions) | 2021 | | 2020 |
| Beginning of Period | $ | 19 | | | $ | 18 | |
| Additions Based on Tax Positions Taken in the Current Year | — | | | 1 | |
| Reductions Based on Positions Taken in Prior Years | (18) | | | — | |
| | | |
| End of Period | $ | 1 | | | $ | 19 | |
Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2021 and 2020. | | | | | | | | | | | |
| ($ in millions) | Amount | | Expiring Year |
| Federal Net Operating Loss | $ | 2 | | | None |
| State Net Operating Loss | 3 | | | 2026 - 27 |
| State Credits | 10 | | | 2023 - 29 |
| | | |
| Federal Investment Tax Credits | 33 | | | 2034 - 42 |
| Federal Production Tax Credits | 26 | | | 2041 - 42 |
| Other Federal Credits | 2 | | | 2034 - 42 |
TEP recorded no interest expense in 20212022 and 20202021 related to uncertain tax positions. In addition, TEP had no interest payable, and no penalties accrued as of December 31, 20212022 and 2020.2021.
TEP has been audited by the IRS through tax year 2010. TEP's 20112014 to 20202021 tax years are open for audit by federal and state tax agencies.
TEP had previously filed an application withIncluded in Accounts Receivable, Net and Accounts Payable on the IRS forConsolidated Balance Sheets are current income taxes receivable and payable that are due from and to affiliates, respectively. TEP’s net intercompany income taxes were a change in accounting method on uncertain tax positions. On February 2,receivable of $1 million and $6 million as of December 31, 2022 and 2021, TEP received approval of this application from the IRS which resulted in a $18 million decrease in uncertain tax position obligations on a prospective basis.respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
TAX SHARING AGREEMENT
Under the terms of the tax sharing agreement with UNS Energy, TEP made net payments of $7 million in 2021 and received net refunds of $10 million in 2020 and $14 million in 2019 related to Federal income tax returns.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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, 2021.2022.
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, 2021.2022. 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, 2021,2022, 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 20212022 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
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.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.
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.
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.
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, PCAOB ID No. 34 (Deloitte), beyond those rendered in connection with their audit and review of TEP’s financial statements, is compatible with maintaining their independence as auditor.
The following table details principal accountant fees paid to Deloitte for professional services: | | (in thousands) | (in thousands) | 2021 | | 2020 | (in thousands) | 2022 | | 2021 |
Audit Fees (1) | Audit Fees (1) | $ | 1,126 | | | $ | 1,027 | | Audit Fees (1) | $ | 1,181 | | | $ | 1,126 | |
Audit-Related Fees (2) | Audit-Related Fees (2) | — | | | 45 | | Audit-Related Fees (2) | 105 | | | — | |
| | Total | Total | $ | 1,126 | | | $ | 1,072 | | Total | $ | 1,286 | | | $ | 1,126 | |
(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 2020.2022.
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
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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| (a) | (1) | Consolidated Financial Statements as of December 31, 20212022 and 2020,2021, and for each of the three years in the period ended December 31, 2021:2022: | |
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| (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. | |
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| (3) | Exhibits | |
| | Reference is made to the Exhibit Index commencing on page 8681. | |
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ITEM 16. FORM 10-K SUMMARY
Not Applicable.
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| Exhibit Index |
| Exhibit No. | | Description |
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| | Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for the year ended December 31, 1996, File No. 1-05924 - Exhibit No 3(a)). |
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| | TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-05924 - Exhibit 3(a)). |
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| | Bylaws of TEP, as amended as of August 12, 2015 (Form 10-Q for the quarter ended September 30, 2015, File No. 1-05924 - Exhibit 3). |
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| | Amendment to Articles of Incorporation of UNS Energy Corporation, creating series of Limited Voting Junior Preferred Stock (Form 8-K dated August 12, 2015, File No. 1-05924 - Exhibit 3.2). |
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| | Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(a)). |
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| | Loan Agreement, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(b)a). |
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| | Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(a)). |
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| | Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(b)). |
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| | Indenture of Trust, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(a)). |
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| | Loan Agreement, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(b)). |
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| | Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as trustee, authorizing unsecured Notes (Form 8-K dated November 8, 2011, File 1-05924 - Exhibit 4.1). |
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| | Supplemental Indenture No. 1, dated May 1, 2022, between Tucson Electric Power Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as trustee, authorizing unsecured Notes (Form S-3 dated May 5, 2022, File No. 333-264708 - Exhibit 4(c)(2)). |
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| | Officers Certificate, dated September 14, 2012, authorizing 3.85% Notes due 2023 (Form 8-K dated September 14, 2012, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated March 10, 2014, authorizing 5.00% Senior Notes due 2044 (Form 8-K dated March 10, 2014, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated February 27, 2015, authorizing 3.05% Senior Notes due 2025 (Form 8-K dated February 27, 2015, File No. 1-05924 - Exhibit 4(a)). |
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| | Officer's Certificate, dated November 29, 2018, authorizing 4.85% Senior Notes due 2048 (Form 10-K for the year ended December 31, 2018, File No. 1-05924 - Exhibit 4(g)(6)). |
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| | Officer's Certificate, dated April 9, 2020, authorizing 4.00% Senior Notes due 2050 (Form 8-K dated April 9, 2020, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated August 10, 2020, authorizing 1.50% Senior Notes due 2030 (Form 8-K dated August 10, 2020, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated May 11, 2021, authorizing 3.25% Senior Notes due 2051 (Form 8-K dated May 11, 2021, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated February 17, 2022, authorizing 3.25% Senior Notes due 2032 (Form 8-K dated February 17, 2022, File No. 1-05924 - Exhibit 4.1). |
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| | Credit Agreement, dated as of October 15, 2021, among Tucson Electric Power Company, MUFG Union Bank, N.A. as Administrative Agent, and a group of lenders (Form 8-K dated October 15, 2021, File No. 1-05924 - Exhibit 4.1). |
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| | Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm. |
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| | Power of Attorney. |
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| | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Susan M. Gray. |
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| | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino. |
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| | Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002). |
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| 101.INS | | XBRL Instance Document. |
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| 101.SCH | | XBRL Taxonomy Extension Schema Document. |
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| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.LAB | | XBRL Taxonomy Extension Label Linkbase Document. |
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| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document. |
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| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document. |
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| 104 | | The cover page from the Company's Annual Report on Form 10-K/A Amendment No. 110-K for the year ended December 31, 2021,2022, formatted in Inline XBRL and contained in Exhibit 101. |
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| * | | Previously filed as indicated and incorporated herein by reference. |
** | | Previously filed in the Company's Annual Report on Form 10-K for the year ended December 31, 2021. |
*** | | Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |
SIGNATURES
Pursuant to the requirements of section 13 or 15(b) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | TUCSON ELECTRIC POWER COMPANY |
| | | (Registrant) |
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| Date: | May 20, 2022February 9, 2023 | | /s/ Frank P. Marino |
| | | Frank P. Marino |
| | | Sr. Vice President, Chief Financial Officer, and Director |
| | | (Principal Financial Officer and Principal Accounting Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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| Date: | May 20, 2022February 9, 2023 | | * |
| | | Susan M. Gray |
| | | President, Chief Executive Officer, and Director |
| | | (Principal Executive Officer) |
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| Date: | May 20, 2022February 9, 2023 | | /s/ Frank P. Marino |
| | | Frank P. Marino |
| | | Sr. Vice President, Chief Financial Officer, and Director |
| | | (Principal Financial Officer and Principal Accounting Officer) |
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| Date: | May 20, 2022February 9, 2023 | | * |
| | | Todd C. Hixon |
| | | Director |
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| | *By: | /s/ Frank P. Marino |
| | | Frank P. Marino |
| | | Attorney-in-fact |