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 and environmental matters;
•critical accounting estimates; and
•new accounting standards issued and not yet adopted.
Management's Discussion and Analysis includes financial information prepared in accordance with GAAP.
Management's Discussion and Analysis should be read in conjunction with the financial statements and accompanying notes that appear in Part I, Item 1 of this Form 10-Q. For information on factors that may cause our actual future results to differ from those we currently anticipate, see Forward-Looking Information at the front of this report and Risk Factors in Part 1, Item 1A of our 2021 Annual Report on Form 10-K/A, and in Part II, Item 1A of this Form 10-Q.
References in this discussion and analysis to "we" and "our" are to TEP.
OUTLOOK AND STRATEGIES
TEP's financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory and legislative actions. Our plans and strategies include:
•Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers.
•Continuing our transition from carbon-intensive sources to a more sustainable energy portfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. Our goal is to reduce carbon emissions by 80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In May 2022, Fortis set a goal to achieve net-zero direct carbon emissions by 2050. The establishment of this additional target reinforces Fortis' commitment, along with that of its subsidiaries, to decarbonize over the long-term, while preserving customer reliability and affordability. These goals may be impacted by various federal and state energy policies, including policies currently under consideration.
•Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
CURRENT ECONOMIC CONDITIONS
The COVID-19 pandemic caused changes in consumer and business behavior and disrupted economic activity in TEP's service territory. Our business continuity plans and protocols are intended to support the continued delivery of safe and reliable service to our customers and the communities we serve. 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.
TEP faces market risks associated with fluctuations in electricity, natural gas, and coal prices, and these commodity price fluctuations can temporarily affect the Company's cash flows prior to recovery through regulatory mechanisms. Particularly in view of heightened geopolitical instability, we cannot project the future level of commodity prices or their volatility.
Table of Contents Performance - The second quarter of 2022 compared with the second quarter of 2021
TEP reported net income of $55 million in the second quarter of 2022 compared with net income of $64 million in the second quarter of 2021. The decrease of $9 million, or 14%, was primarily due to:
•$5 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions;
•$5 million in higher base operations and maintenance expenses primarily due to an increase in generation operations and outside service expenses; partially offset by a decrease in planned outages in 2022;
•$5 million in lower retail revenue primarily due to lower usage as a result of less favorable weather; and
•$3 million in higher depreciation expense primarily due to an increase in asset base.
The decrease was partially offset by:
•$7 million in higher margin from wholesale transactions primarily due to an increase in sales volume; and
•$3 million in higher transmission revenue due to the 2019 FERC Rate Order settlement agreement triggering recognition of revenue previously reserved for refund.
Performance - The first six months of 2022 compared with the first six months of 2021
TEP reported net income of $74 million in the first six months of 2022 compared with net income of $86 million in the first six months of 2021. The decrease of $12 million, or 14%, was primarily due to:
•$10 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions;
•$10 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;
•$8 million in higher depreciation expense primarily due to an increase in asset base; and
•$3 million in higher base operation and maintenance expenses primarily due to an increase in generation operations and outside service expenses; partially offset by a decrease in planned outages in 2022.
The decrease was partially offset by:
•$16 million in higher margin from wholesale transactions primarily due to an increase in sales volume; and
•$5 million in higher transmission revenue due to the 2019 FERC Rate Order settlement agreement triggering recognition of revenue previously reserved for refund.
FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to regulatory matters, generation resource strategy, and weather patterns.
We are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2021 Annual Report on Form 10-K/A and new regulatory matters occurring in 2022.
2022 Rate Case
In June 2022, we filed a general rate case with the ACC based on a test year ended December 31, 2021.
Our key 2022 Rate Case proposals are described below:
•a $136 million net increase in retail revenues comprised of the following components:
Table of Contents •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, that result in an $18 million reduction in revenues collected from customers.
•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%;
•a capital structure for rate making purposes of approximately 54% common equity and 46% long-term debt; and
•a new Resource Transition Mechanism 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 2020, the ACC 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 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. In January 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. We cannot predict the timing or outcome of these proceedings.
Energy Imbalance Market
In 2019, we signed an agreement with the California Independent System Operator indicating our intent to begin participating in the EIM by spring of 2022. The EIM is a real-time energy market intended to find automatically 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 demonstrate resource adequacy through a combination of owned or contracted resources. Our participation in the EIM is expected to: (i) reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance reliability through improved system utilization and responsiveness. We entered into the EIM in May 2022.
2019 FERC Rate Order
In 2019, we filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more 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 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 settlement agreement include, but are not limited to:
•replacing our stated transmission rates with a single forward-looking formula rate;
•a 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.
Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. Amounts deferred as a regulatory liability in excess of the rates approved in the settlement agreement are being returned to customers. We will return the remaining refunds to customers in the third quarter of 2022. We had $10 million as of June 30, 2022, and $15 million as of December 31, 2021, of wholesale revenues reserved in Current Liabilities-Regulatory Liabilities on the Condensed Consolidated Balance Sheets.
Table of Contents Other FERC Matters
In January 2021, the FERC notified us that it was commencing an audit that intends 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 covers the period of January 1, 2018 to the present. The audit is ongoing and we cannot predict the outcome or findings, if any, of the FERC audit at this time.
Generation Resource Strategy
Our long-term strategy is to continue our shift from carbon-intensive sources to a more sustainable energy portfolio including expanding renewable energy resources while reducing reliance on coal-fired generation resources. In 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.
In February 2022, the ACC acknowledged our 2020 IRP, and found it to be reasonable and in the public interest. Our 2020 IRP calls for us to reduce our carbon emissions by 80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In April 2022, we issued an All-Source Request for Proposals (ASRFP), which requests new wind and solar generation, energy storage systems and other resources such as energy efficiency resources. As part of the ASRFP, we are seeking bids for all resource types, including:
•up to 250 MW of renewable and energy efficiency resources, including new wind and solar generation systems and new energy efficiency initiatives, including demand response programs that reduce usage during periods of high energy demand; and
•up to 300 MW of "firm capacity" resources that can be called on at any time, including energy storage systems designed to provide at least four hours of continuous energy every day during the summer for us to dispatch as needed.
Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we plan to exit all ownership interests in coal-fired generation facilities over the next decade. On June 30, 2022, San Juan Unit 1 was retired, which decreased coal-fired generating capacity by 170 MW. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions. The execution of our 2020 IRP is dependent on obtaining regulatory recovery in future rate proceedings. We filed the 2022 Rate Case with the ACC in June 2022.
Renewable Energy Projects
In 2021 and 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.
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. The strategy provides a shift towards renewable generation and further decreases our dependency on coal-fired generation.
Production Tax Credits
PTCs are per kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In May 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and primarily recognized in the third quarter due to weather patterns and other factors that contribute to seasonal fluctuations in earnings. Oso Grande recorded approximately $6 million and $8 million in PTCs in the three and six months ended June 30, 2022, respectively. The IRS published PTC rate for electricity produced by a qualified facility using wind was $0.025 for 2021 and $0.026 for 2022.
If actual availability of the Oso Grande wind turbines is below a contractually established availability factor, we are entitled to liquidated damages to partially offset operation and maintenance costs incurred. We recorded a reduction in Operations and Maintenance on the Condensed Consolidated Statements of Income of $1 million in the three and six months ended June 30, 2022, related to Oso Grande liquidated damages. Any liquidated damages in excess of operating expenses will reduce Utility
Table of Contents Plant-Plant in Service on the Condensed Consolidated Balance Sheets. The PTCs and liquidated damages will mostly offset the operating expenses of Oso Grande, which is not currently 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 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, 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, the Governor of Arizona signed legislation 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.
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.
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.
See Part II, Item 7A in our 2021 Annual Report on Form 10-K/A and Part I, Item 3 of this Form 10-Q for information regarding interest rate risk and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of 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, RES Tariff, DSM, and TEAM are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on cost recovery mechanisms.
•Short-Term Wholesale Sales - Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC cost recovery mechanism.
•Springerville Units 3 and 4 - Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.
Table of Contents The following discussion provides the significant items that affected TEP's results of operations in the second quarter and first six months of 2022 compared with the same periods in 2021 presented on a pre-tax basis.